**Exhibit 99.3**

 

**MANAGEMENT’SDISCUSSION AND ANALYSIS AND RESULTS OF OPERATIONS**

 

**For theFiscal Year Ended December 31, 2008**

 

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This management’s discussion and analysis (“MD&A”) is the Trustmanagement’s analysis of its financial performance and significant trends orexternal factors that may affect future performance.  It is dated February 10, 2009 and shouldbe read in conjunction with the audited Consolidated Financial Statements as atand for the year ended December 31, 2008, the audited Consolidated FinancialStatements and MD&A as at and for the year ended December 31, 2007,the MD&A and the unaudited Consolidated Financial Statements as at and forthe periods ended March 31, 2008, June 30, 2008 andSeptember 30, 2008 as well as the Trust’s Annual InformationForm that is filed on SEDAR at www.sedar.com.

 

The MD&A contains Non-GAAPmeasures and forward-looking statements and readers are cautioned that theMD&A should be read in conjunction with the Trust’s disclosure under“Non-GAAP Measures” and “Forward-Looking Statements” included at the end ofthis MD&A.

 

**Executive Overview**

 

ARCEnergy Trust (“ARC”) is one of the top 20 producers of conventional oil and gasin western Canada.  ARC as at December 31,2008 held interests in excess of 18,600 wells with approximately 5,600 wellsoperated by ARC and the remainder operated primarily by other major oil and gascompanies.  ARC’s production has averagedbetween 61,000 and 67,000 boe per day in each quarter for the last threeyears.  The total capitalization of ARC,which trades on the Toronto Stock Exchange, as at December 31, 2008 was$5.4 billion as shown on Table 23. Subsequent to year-end, the Trust completed an equity offering of 15.5million units for net proceeds of $240 million bringing the total capitalizationto approximately $4 billion as at February 10, 2009.

 

ARC’sobjective as an energy company is to provide superior and sustainable long-termreturns to unitholders.  Key attributesof the business plan include:

 

·      Concentrated activities in three major business areas: conventional oiland natural gas assets, resource plays and enhanced oil recoveryinitiatives.  In addition to these majorinitiatives, ARC continually reviews acquisition and disposition opportunitiesto high-grade its asset base and provide future growth opportunities.

 

·      Pay a portion of cash flow to unitholders annually.  Currently the Trust distributes $0.12 perunit per month.  The remainder of thecash flow is used to fund reclamation costs, and a portion of capitalexpenditures and land acquisitions. Since the Trust’s inception in July 1996 to December 31, 2008,the Trust has distributed $3.2 billion or $23.70 per unit.

 

·      Annual replacement of production and reserves through drilling new wellsand associated oil and natural gas development activities.  The vast majority of the annual capitalbudget is being deployed on a balanced drilling program of low and moderaterisk wells, well tie-ins and other related costs, and the acquisition of 

 

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·      undeveloped land. The Trust continues to focus on major properties withsignificant upside, with the objective to replace production declines throughinternal development opportunities. Calculated on a boe basis, ARC’s normalized reserves per unit have increasedfrom 1.40 to 1.42; production per unit has decreased slightly from 0.31 to 0.29while the Trust has made distributions of $7.47 per unit or $1.6 billion from January 1,2006 through to December 31, 2008. Details of the calculations for normalized production and reserves perunit are provided in Table 1.

 

·      The periodic acquisition of strategic producing and undevelopedproperties to enhance current production or provide the potential for futuredrilling locations and if successful, additional production and reserves.

 

·      Using prudent production practices to maximize the recovery of oil andnatural gas from the reservoirs.

 

·      Controlling costs for both routine operatingexpenditures and costs incurred for capital projects.  ARC expects that the aggregate amount ofoperating costs will increase over time as ARC adds approximately 300 wells peryear to its operating base to replace the natural decline on existing producingwells.

 

ARC’sbusiness plan and operating practices also include the following strategies andaction plans that are being undertaken to increase ARC’s competitiveness andfuture profitability:

 

·      Continual development of staff expertise and the hiring and retention ofsome of the industry’s best and most qualified personnel.

 

·      Building relationships with suppliers, joint venture partners,government and other stakeholders and conducting business in a fair andequitable manner.

 

·      Reviewing our structure in order to optimize returns to investors withthe commencement of the trust taxation on January 1, 2011.  ARC’s most likely course of action will be toconvert to a corporation, subject to unitholder approval.

 

·      Promoting the use of proven and effective technologies to enhance therecoverable resources in place and reduce costs.

 

·      Being an industry leader in health, safety and environmentalperformance.

 

·      Actively supporting local initiatives and charities in the communitiesin which we live and work.

 

 

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**Table 1**

 
| **Per Trust Unit**                | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|---------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Normalized production per unit (1) (2) | ** ** | **0.29** |       | 0.30     |       | 0.31     |       |
| Normalized reserves per unit (1) (3)   | ** ** | **1.42** |       | 1.35     |       | 1.40     |       |
| Distributions per unit                      | ** ** | **$**    | **2.67**   |     | $          | 2.40     |       | $ | 2.40 |   |
|                                             |            |          |            |          |            |          |            |  |  |  |

 

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(1)   Normalized indicates that all years as presented have been adjusted toreflect a net debt to capitalization of 15 per cent. It is assumed thatadditional trust units were issued (or repurchased) at a period end price forthe reserves per unit calculation and at an annual average price for theproduction per unit calculation in order to achieve a net debt balance of 15per cent of total capitalization each year. The normalized amounts arepresented to enable comparability of annual per unit values.

(2)   Production per unit represents daily average production (boe) perthousand trust units.  Calculated basedon daily average production divided by the normalized weighted average trustunits outstanding including trust units issuable for exchangeable shares.

(3)   Reserves per unit are calculated based on proved plus probable reserves(boe) divided by period end trust units outstanding including trust unitsissuable for exchangeable shares.

 

Theeffectiveness of ARC’s business plan can best be measured by historical resultsas shown in Table 2.  Commodity pricesand the ongoing economic crisis are significant factors in determiningprofitability and market returns of the units. The successful execution of ARC’s business plan and operationalsuccesses, contributed to our 9.7 per cent annual return for 2008 despite thenegative impact of external factors.

 

**Table 2**

 
| **Total Returns ****(1)****($ per unit except for per cent)** | ** ** | **Trailing One Year** | ** ** | **Trailing Three Year** | ** ** | **Trailing Five Year** | ** ** |
|-------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|-----------------------------------|------------|----------------------------------|------------|
| Distributions per unit                                                                                | ** ** | **$**                           | **2.67**   |                              | $          | 7.47                             |       | $ | 11.26 |   |
| Capital appreciation per unit                                                                         | ** ** | **$**                           | **(0.30**  | **)**                             | $          | (6.39                            | )          | $ | 5.36 |   |
| Total return per unit                                                                                 | ** ** | **$**                           | **2.37**   |                              | $          | 1.08                             |       | $ | 16.62 |   |
| Annualized total return per unit                                                                      | ** ** | **9.7**                         | **%**      | 1.1                               | %          | 17.9                             | %          |

 

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(1)   Calculated as at December 31, 2008.

 

**2008 Review and 2009 Guidance**

 

Table 3 is a summary of the Trust’s 2009 RevisedGuidance and a review of 2008 actual results compared to guidance:

** **

**Table 3**

 
| ** **                                                      | ** ** | **2008 Guidance** | ** ** | **2008 Actual** | ** ** | **% Change** | ** ** | **2009  Guidance** | ** ** |
|-----------------------------------------------------------------|------------|------------------------|------------|----------------------|------------|-------------------|------------|--------------------|------------|
| Production (boe/d)                                              |       | 64,000-65,000          |       | 65,126               |       | —            | ** ** | **64,000-65,000**  | ** ** |
| Expenses ($/boe):                                               | ** ** | ** **             | ** ** | ** **           | ** ** | ** **        |       | ** **         | ** ** |
| Operating costs                                                 |       | 10.20                  |       | 10.13                |       | (1                | )          | **10.70**          | ** ** |
| Transportation                                                  |       | 0.80                   |       | 0.80                 |       | —            |       | **1.15**           | ** ** |
| G&A expenses (1)                                            |       | 2.75                   |       | 2.57                 |       | (7                | )          | **2.80**           | ** ** |
| Interest                                                        |       | 1.50                   |       | 1.38                 |       | (8                | )          | **1.85**           | ** ** |
| Capital expenditures ($millions)                                |       | 530                    |       | 548.6                |       | 4                 |       | **450**            | ** ** |
| Weighted average trust units and units  issuable (millions) (2) |       | 216                    |       | 216                  |       | —            |       | **235**            | ** ** |

 

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(1)   The components of the $2.80 per boe G&Aguidance for the full year are as follows: cash G&A - $1.80 per boe; cashcomponent of LTIP - $0.85 per boe; non-cash LTIP component - $0.15 per boe

(2)   2009 guidance for weighted average trust unitshas been revised to include the 15.5 million trust units issued on February 6,2009 under the Trust’s equity offering.

 

3

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The 2009 Guidanceprovides unitholders with information of management’s expectations for resultsof operations for 2009. Readers are cautioned that the 2009 Guidance may not beappropriate for other purposes.

 

Actual results for 2008 were in line with 2008guidance with some minor exceptions as follows:

 

·      G&A expenses of $2.57 per boe were lower than guidance of $2.75 perboe due primarily to the decrease in the trust unit price at year-end whichresulted in a lower non-cash LTIP expense of $0.05 per boe as compared to theguidance amount of $0.15 per boe.

 

·      Interest expense for 2008 was $1.38 as compared to guidance of $1.50 dueto lower short-term interest rates on the Trust’s floating rates debt.  In addition, with record cash flow levelsposted, the Trust was able to cash fund a higher portion of capitalexpenditures in the year.

 

·      Capital expenditures exceeded guidance by $18.6 million due toadditional expenditures and crown land purchases incurred in the Northern areaduring the fourth quarter of 2008.

 

**2008 Annual Financial and Operational Results**

 

Followingis a discussion of ARC’s 2008 annual financial and operating results.

 

**FinancialHighlights**

 

**Table4**

 
| **(Cdn $ millions, except per unit and volume data)** | ** ** | **2008**   | ** ** | **2007** | ** ** | **% Change** | ** ** |
|-----------------------------------------------------------------------------------------------|------------|------------|------------|----------|------------|-------------------|------------|
| Cash flow from operating activities                                                           | ** ** | **944.4**  |       | 704.9    |       | 34                |       |
| Cash flow from operating activities per  unit (1)                                             | ** ** | **4.37**   |       | 3.35     |       | 30                |       |
| Net income                                                                                    | ** ** | **533.0**  |       | 495.3    |       | 8                 |       |
| Net income per unit (2)                                                                       | ** ** | **2.50**   |       | 2.39     |       | 5                 |       |
| Distributions per unit (3)                                                                    | ** ** | **2.67**   |       | 2.40     |       | 11                |       |
| Distributions as a per cent of cash flow  from operating activities                           | ** ** | **60**     |       | 71       |       | (15               | )          |
| Average daily production (boe/d) (4)                                                          | ** ** | **65,126** |       | 62,723   |       | 4                 |       |

 

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(1)   Per unit amounts are based on weighted average trust units outstandingplus trust units issuable for exchangeable shares at year-end.

(2)   Based on net income after non-controlling interest divided by weightedaverage trust units outstanding excluding trust units issuable for exchangeableshares.

(3)   Based on number of trust units outstanding at each cash distributiondate.

(4)   Reported production amount is based on company interest before royaltyburdens. Where applicable in this MD&A natural gas has been converted tobarrels of oil equivalent (“boe”) based on 6 mcf: 1 bbl. The boe rate is basedon an energy equivalent conversion method primarily applicable at the burnertip and does not represent a value equivalent at the well head. Use of boe inisolation may be misleading.

 

**Net Income**

 

Net income in 2008 was$533 million ($2.50 per unit), an increase of $37.7 million from $495.3 million($2.39 per unit) in 2007.  While cashflow from operating activities increased $239.5 million in 2008 compared to thesame period in 

 

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2007 (see Table 6 fordetails), there were several non-cash items that impacted the Trust’s netincome in the current year as follows:

 

·      The Trust recorded a $68 million unrealized gain on risk managementcontracts, a $123.9 million increase compared to an unrealized loss of $55.9million for the same period of 2007.  Theunrealized gain was attributed to the sharp decline in commodity prices atyear-end.

 

·      The Trust recorded an $88.5 million non-cash foreign exchange loss onits U.S. denominated debt as a result of the weakening of the Canadian dollarrelative to the U.S. dollar during 2008 compared to a non-cash gain of $69.6million in 2007.

 

·      The Trust recorded a non-cash provision for non-recoverable accountsreceivable of $32 million in 2008 ($nil in 2007) due primarily to a provisionof $30.6 million recorded for an account receivable from one counterparty thatmarketed a portion of the Trust’s production. See section titled Provision for Non-recoverable Accounts Receivable fordetails.

 

·      The Trust recorded a $4.5 million future income tax recovery for 2008compared to a $121.3 million recovery in 2007. The 2007 future income tax recovery was attributed to a significantchange in the Trust’s future tax rate that came into effect during the year ascompared to a small rate change in 2008.

 

A measure of sustainability is the comparisonof net income to distributions. Net income incorporates all costs includingdepletion expense and other non-cash expenses whereas cash flow from operatingactivities measures the cash generated in a given period before the cost ofacquiring or replacing the associated reserves produced. Therefore, net incomemay be more representative of the profitability of the entity and thus arelevant measure against which to measure distributions to illustratesustainability. As net income is sensitive to fluctuations in commodity pricesand the impact of risk management contracts, currency fluctuations and othernon-cash items, it is expected that there will be deviations between annual netincome and distributions. Table 5 illustrates the annual shortfall ofdistributions to net income as a measure of long-term sustainability.

 

**Table 5**

 
| **Net income and Distributions  ($ millions except per cent)** | ** ** | **2008** | ** ** | **2007** | ** ** | **2006** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Net income                                                                                        |       | 533.0    |       | 495.3    |       | 460.1    |       |
| Distributions                                                                                     |       | 570.0    |       | 498.0    |       | 484.2    |       |
| Excess (Shortfall)                                                                                |       | (37.0    | )          | (2.7     | )          | (24.1    | )          |
| Excess (Shortfall) as per cent of net  income                                                     |       | (7       | )%         | (1       | )%         | (5       | )%         |
| Cash flow from operating activities                                                               |       | 944.4    |       | 704.9    |       | 734.0    |       |
| Distributions as a per cent of cash flow  from operating activities                               |       | 60       | %          | 71       | %          | 66       | %          |

 

**Cash Flow from Operating Activities**

 

Cash flow fromoperating activities increased by 34 per cent in 2008 to $944.4 million from$704.9 million in 2007. The increase in 2008 cash flow from operatingactivities is detailed in Table 6.

 

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**Table 6**

 
| ** **                                    | ** ** | **($ millions)** | ** ** | **($ per trust unit)** | ** ** | **(% variance)** | ** ** |
|-----------------------------------------------|------------|-----------------------|------------|---------------------------------------|------------|-----------------------|------------|
| **2007  Cash flow from Operating Activities** | ** ** | **704.9**             | ** ** | **3.35**                              | ** ** | **—**            | ** ** |
| Volume variance                               |       | 51.5                  |       | 0.25                                  |       | 7                     |       |
| Price variance                                |       | 403.3                 |       | 1.91                                  |       | 57                    |       |
| Cash losses on risk management contracts      |       | (89.8                 | )          | (0.43                                 | )          | (13                   | )          |
| Royalties                                     |       | (88.3                 | )          | (0.42                                 | )          | (13                   | )          |
| Expenses:                                     |       |                  |       |                                  |       |                  |       |
| Transportation                                |       | (2.6                  | )          | (0.01                                 | )          | —                |       |
| Operating (1)                                 |       | (23.5                 | )          | (0.11                                 | )          | (3                    | )          |
| Cash G&A                                  |       | (14.2                 | )          | (0.07                                 | )          | (2                    | )          |
| Interest                                      |       | 4.0                   |       | 0.02                                  |       | 1                     |       |
| Realized foreign exchange loss                |       | (0.7                  | )          | —                                |       | —                |       |
| Weighted average trust units                  |       | —                |       | (0.12                                 | )          | —                |       |
| Non-cash and other items (2)                  |       | (0.2                  | )          | —                                |       | —                |       |
| **2008  Cash flow from Operating Activities** | ** ** | **944.4**             | ** ** | **4.37**                              | ** ** | **—**            | ** ** |

 

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(1)       Excludes non-cash portion of LTIP expense recorded in operating costs.

(2)       Includes the changes in non-cash working capital and expenditures onsite restoration and reclamation.

 

**2009 Cash Flow from Operating Activities Sensitivity**

 

Table 7 illustrates sensitivities topre-hedged operating income items with operational changes and changes to thebusiness environment:

 

**Table 7**

 
| ** **                              | ** ** | ** **     | ** ** | **Impact on Annual  Cash flow from Operating Activities ****(2)** | ** ** |
|-----------------------------------------|------------|----------------|------------|------------------------------------------------------------------------------------------------------|------------|
| **Business Environment**           | ** ** | **Assumption** | ** ** | **Change**                                                                                           | ** ** | **$/Unit** | ** ** |
| Oil  price (US$WTI/bbl) (1)             |       | $              | 48.55      |                                                                                                 | $          | 1.00 |   | $ | 0.04 |   |
| Natural gas price (Cdn $AECO/mcf) (1)   |       | $              | 5.95       |                                                                                                 | $          | 0.10 |   | $ | 0.02 |   |
| Cdn$/US$exchange rate                   |       | 1.27           |       | $                                                                                                    | 0.01       |   | $ | 0.02 |   |
| Interest rate on debt                   |       | %              | 5.75       |                                                                                                 | %          | 1.0 |   | $ | 0.02 |   |
| **Operational**                         | ** ** | ** **     | ** ** | ** **                                                                                           | ** ** | ** ** | ** ** |
| Liquids  production volume (bbl/d)      |       | 31,500         |       | %                                                                                                    | 1.0        |   | $ | 0.03 |   |
| Gas  production volumes (mmcf/d)        |       | 195.0          |       | %                                                                                                    | 1.0        |   | $ | 0.02 |   |
| Operating  expenses per boe             |       | $              | 10.70      |                                                                                                 | %          | 1.0 |   | $ | 0.01 |   |
| Cash  G&A and LTIP expenses per boe |       | $              | 2.65       |                                                                                                 | %          | 10.0 |   | $ | 0.03 |   |
|                                         |            |                |            |                                                                                                      |            |  |  |  |  |  |  |  |

 

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(1)       Analysis does not include the effect of hedging contracts.

(2)       Assumes constant working capital.

 

**Production**

 

Production volumes averaged 65,126 boe per day in 2008 compared to62,723 boe per day in 2007 as detailed in Table 8.  Late in the fourth quarter of 2007, the Trustbrought on new production in both the Dawson and Pouce Coupe areas, achievingexit production of 65,000 boe per day in December 2007 and maintained thatproduction level throughout the full year of 2008.

 

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**Table 8**

 
| **Production**                            | ** ** | **2008**   | ** ** | **2007**   | ** ** | **% Change** | ** ** |
|-------------------------------------------|------------|------------|------------|------------|------------|-------------------|------------|
| Light & medium crude oil (bbl/d) | ** ** | **27,239** | ** ** | **27,366** | ** ** | **—**        | ** ** |
| Heavy oil (bbl/d)                         | ** ** | **1,274**  | ** ** | **1,316**  | ** ** | **(3**            | **)**      |
| Natural gas (mmcf/d)                      | ** ** | **196.5**  | ** ** | **180.1**  | ** ** | **9**             | ** ** |
| NGL (bbl/d)                               | ** ** | **3,861**  | ** ** | **4,027**  | ** ** | **(4**            | **)**      |
| Total production (boe/d) (1)              | ** ** | **65,126** | ** ** | **62,723** | ** ** | **4**             | ** ** |
| % Natural gas production                  | ** ** | **50**     | ** ** | **48**     | ** ** | **4**             | ** ** |
| % Crude oil and liquids production        | ** ** | **50**     | ** ** | **52**     | ** ** | **(4**            | **)**      |

 

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(1)       Reported production for a period may include minor adjustments fromprevious production periods.

 

In 2008, oil production decreased slightly to 27,239 boe per day from27,366 boe per day in 2007. Natural gas production was 196.5 mmcf per day in2008, an increase of nine per cent from the 180.1 mmcf per day produced in2007. The increased gas production was a result of the Trust’s active drillingprogram in the Dawson area and the completion of a third party operated gasplant.

 

The Trust’s objective is to maintain annual production through thedrilling of wells and other development activities. In fulfilling thisobjective, there may be fluctuations in production depending on the timing ofnew wells coming on-stream. During 2008, the Trust drilled 232 gross wells (178net wells) on operated properties; 138 gross oil wells, and 93 gross naturalgas wells with a 99 per cent success rate.

 

The Trust expects that 2009 full year production will be approximately64,000 to 65,000 boe per day and that 191 gross wells (171 net wells) will bedrilled by ARC on operated properties with participation in an additional 112gross wells to be drilled on the Trust’s non-operated properties. The Trustestimates that the 2009 drilling program will add sufficient production fromnew wells to offset production declines on existing properties. The plannedcapital expenditures will be continuously monitored in the context of thecurrent economic environment and will be revised as required.

 

Table 9 summarizes the Trust’s production by core area:

 

**Table 9**

 
| ** **                          | ** ** | **2008**    | ** ** | **2007**    | ** ** |
|-------------------------------------|------------|-------------|------------|-------------|------------|
| **Production**                      | ** ** | **Total**   | ** ** | **Oil**     | ** ** | **Gas** | ** ** | **NGL** | ** ** | **Total** | ** ** | **Oil** | ** ** | **Gas** | ** ** | **NGL** | ** ** |
| **Core Area**** ****(1)** | ** ** | **(boe/d)** | ** ** | **(bbl/d)** | ** ** | **(mmcf/d)** | ** ** | **(bbl/d)** | ** ** | **(boe/d)** | ** ** | **(bbl/d)** | ** ** | **(mmcf/d)** | ** ** | **(bbl/d)** | ** ** |
| Central AB                          | ** ** | **7,495**   | ** ** | **1,406**   | ** ** | **29.2** | ** ** | **1,218** |   | 7,967 |   | 1,596 |   | 30.3 |   | 1,319 |   |
| Northern AB & BC           | ** ** | **22,469**  | ** ** | **5,318**   | ** ** | **93.7** | ** ** | **1,534** |   | 19,797 |   | 5,773 |   | 74.8 |   | 1,552 |   |
| Pembina & Redwater         | ** ** | **13,707**  | ** ** | **9,495**   | ** ** | **19.7** | ** ** | **936** |   | 13,703 |   | 9,474 |   | 19.2 |   | 1,034 |   |
| S.E. AB & S.W. Sask.       | ** ** | **9,701**   | ** ** | **985**     | ** ** | **52.2** | ** ** | **11** |   | 10,040 |   | 1,044 |   | 53.9 |   | 10 |   |
| S.E. Sask. & MB            | ** ** | **11,754**  | ** ** | **11,309**  | ** ** | **1.7** | ** ** | **162** |   | 11,216 |   | 10,795 |   | 1.9 |   | 112 |   |
| **Total**                           | ** ** | **65,126**  | ** ** | **28,513**  | ** ** | **196.5** | ** ** | **3,861** |   | 62,723 |   | 28,682 |   | 180.1 |   | 4,027 |   |

 

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(1)       Provincial references: AB is Alberta, BC is British Columbia, Sask. isSaskatchewan, MB is Manitoba, S.E. is southeast and S.W. is southwest.

 

7

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**Revenue**

 

Revenue increased to an historical high of $1.7 billion in 2008, $454.8million higher than 2007 revenues of $1.3 billion. While oil volumes wererelatively unchanged year over year, the increase in realized oil pricesgenerated additional oil revenue of $258.3 million. Natural gas revenue increasedby $173.4 million, comprising a $120.6 million increase due to higher pricesrealized in 2008 and a $52.8 million increase due to higher volumes produced in2008.

 

A breakdown of revenue is outlined in Table 10:

 

**Table 10**

 
| **Revenue**                 | ** ** | ** **  | ** ** | ** **  | ** ** | ** **        | ** ** |
|-----------------------------|------------|-------------|------------|-------------|------------|-------------------|------------|
| **($ millions)**       | ** ** | **2008**    | ** ** | **2007**    | ** ** | **% Change** | ** ** |
| **Oil revenue**             | ** ** | **983.1**   | ** ** | **724.8**   | ** ** | **36**            | ** ** |
| Natural gas revenue         | ** ** | **616.8**   | ** ** | **443.4**   | ** ** | **39**            | ** ** |
| **NGL revenue**             | ** ** | **98.5**    | ** ** | **80.5**    | ** ** | **22**            | ** ** |
| **Total commodity revenue** | ** ** | **1,698.4** | ** ** | **1,248.7** | ** ** | **36**            | ** ** |
| **Other revenue**           | ** ** | **8.0**     | ** ** | **2.9**     | ** ** | **176**           | ** ** |
| **Total revenue**           | ** ** | **1,706.4** | ** ** | **1,251.6** | ** ** | **36**            | ** ** |

 

**Commodity Prices Prior to Hedging**

 

**Table 11**

 
| ** **                                     | ** ** | **2008**   | ** ** | **2007**   | ** ** | **% Change** | ** ** |
|------------------------------------------------|------------|------------|------------|------------|------------|-------------------|------------|
| **Average  Benchmark Prices**                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** **        | ** ** |
| AECO gas ($/mcf) (1)                           | ** ** | **8.13**   | ** ** | **6.61**   | ** ** | **23**            | ** ** |
| WTI oil (US$/bbl) (2)                          | ** ** | **99.66**  | ** ** | **72.37**  | ** ** | **38**            | ** ** |
| Cdn$/ US$foreign exchange rate                 | ** ** | **1.05**   | ** ** | **1.06**   | ** ** | **(1**            | **)**      |
| WTI oil (Cdn$/bbl)                             | ** ** | **104.30** | ** ** | **77.35**  | ** ** | **35**            | ** ** |
| **ARC  Realized Prices Prior to Hedging**      | ** ** | ** ** | ** ** | ** ** | ** ** | ** **        | ** ** |
| Oil ($/bbl)                                    | ** ** | **94.20**  | ** ** | **69.24**  | ** ** | **36**            | ** ** |
| Natural gas ($/mcf)                            | ** ** | **8.58**   | ** ** | **6.75**   | ** ** | **27**            | ** ** |
| NGL ($/bbl)                                    | ** ** | **69.71**  | ** ** | **54.79**  | ** ** | **27**            | ** ** |
| Total commodity revenue before hedging ($/boe) | ** ** | **71.25**  | ** ** | **54.54**  | ** ** | **31**            | ** ** |
| Other revenue ($/boe)                          | ** ** | **0.34**   | ** ** | **0.13**   | ** ** | **162**           | ** ** |
| **Total revenue before hedging** ($/boe)       | ** ** | **71.59**  | ** ** | **54.67**  | ** ** | **31**            | ** ** |

 

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(1)       Represents the AECO monthly posting.

(2)       WTI represents West Texas Intermediate posting as denominated in US$.

 

Although oil prices achievedrecord highs throughout 2008, peaking in July at US$147.27 per barrel forWTI and averaging US$99.66 per barrel for the full year, the sharp decline inoil prices during the fourth quarter of 2008 has resulted in exit 2008 oilprices at their lowest level since 2002. The full impact of the price declinewill not be realized until the first quarter of 2009.  The average Cdn$/US$ foreign exchange ratewas 1.05 for the full year of 2008; however, a sharp decline in the fourthquarter resulted in the Canadian dollar closing at 1.22 per U.S. dollar on December 31,2008. The negative correlation between the Canadian dollar and U.S. dollardenominated West Texas Intermediate oil prices should lessen the impact on theTrust of any future declines in the price of oil, however, crude oil priceshave remained depressed in the early part of 2009 and investors should expectthat revenues in 2009 will be significantly lower than those recorded in 2008.

 

8

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The Trust’s oil production consists predominantly of light and mediumcrude oil while heavy oil accounts for less than five per cent of the Trust’scrude oil production.  The realized pricefor the Trust’s oil, before hedging, increased 36 per cent to $94.20 from$69.24 for the full year of 2007.

 

Alberta AECO Hub natural gas prices, which are commonly used as anindustry reference, averaged $8.13 per mcf in 2008 compared to $6.61 per mcf in2007. In 2008, ARC’s realized gas price, before hedging, increased by 27 percent to $8.58 per mcf compared to $6.75 per mcf in 2007. ARC’s realized gasprice is based on prices received at the various markets in which the Trustsells its natural gas. ARC’s natural gas sales portfolio consists of gas salespriced at the AECO monthly index, the AECO daily spot market, eastern andmid-west United States markets and a portion to aggregators.

 

Prior to hedging activities,ARC’s total realized commodity price was $71.59 per boe in 2008, a 31 per centincrease from the $54.67 per boe received prior to hedging in 2007.

 

**Risk Management and HedgingActivities**

 

ARCcontinues to maintain an ongoing risk management program to reduce thevolatility of revenues in order to increase the certainty of distributions,protect acquisition economics, and fund capital expenditures. The riskmanagement program was revised in 2005 to maintain a significant portion ofupside price participation on production volumes.

 

Gain or loss on risk managementcontracts comprise realized and unrealized gains or losses on risk managementcontracts that do not meet the accounting definition requirements of aneffective hedge, even though the Trust considers all risk management contractsto be effective economic hedges. Accordingly, gains and losses on such contractsare shown as a separate category in the statement of income.

 

Strongcommodity prices throughout most of 2008 had a significant impact on the Trust’srevenue; however, these strong prices resulted in realized cash losses of $67.8million and $11.4 million for the Trust’s oil and natural gas risk managementcontracts, respectively.

 

During2008, the Trust recorded a $16.2 million realized cash gain due primarily tothe unwinding of foreign exchange risk management contracts, which had lockedin the foreign exchange rates on future principal debt repayments of US$127.2million at an average rate of (1.02 Cdn$/US$). Conversely, the Trust recorded a net cash loss of $12.7 million on itsinterest rate risk management contracts. Included in this balance is a loss of $13.6 million related to treasurylock contracts that were unwound in the first quarter of 2008.

 

ARC’s2008 results include an unrealized total mark-to-market gain of $68 millionwith a net unrealized mark-to-market gain position of $6.7 million as at December 31,2008. The mark-to-market values represent the market price to buy-out the Trust’scontracts as of December 31, 2008 and may be different from what willeventually be realized.

 

9

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Table12 summarizes the total gain (loss) on risk management contracts for theyear-over-year change as of the 2008 year-end:

** **

**Table 12**

 
| **Risk Management Contracts****($ millions)** | ** ** | **Crude Oil  & Liquids** | ** ** | **Natural****Gas** | ** ** | **Foreign  Currency** | ** ** | **Power**  | ** ** | **Interest** | ** ** | **2008  Total** | ** ** | **2007  Total** | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------|------------|--------------------|------------|-----------------------|------------|------------|------------|--------------|------------|-----------------|------------|-----------------|------------|
| **Realized cash gain (loss) on  contracts****(1)**           | ** ** | **(67.8**                              | **)**      | **(11.4**          | **)**      | **16.2**              | ** ** | **—** | ** ** | **(12.7**    | **)**      | **(75.7**       | **)**      | **14.1**        | ** ** |
| **Unrealized gain (loss) on  contracts****(2)**              | ** ** | **50.7**                               | ** ** | **12.4**           | ** ** | **(2.6**              | **)**      | **3.0**    | ** ** | **4.5**      | ** ** | **68.0**        | ** ** | **(55.9**       | **)**      |
| **Total gain (loss) on risk  management contracts**          | ** ** | **(17.1**                              | **)**      | **1.0**            | ** ** | **13.6**              | ** ** | **3.0**    | ** ** | **(8.2**     | **)**      | **(7.7**        | **)**      | **(41.8**       | **)**      |

 

----

(1)       Realized cash gains and losses representactual cash settlements or receipts under the respective contracts.

(2)       The unrealized (loss) gain on contractsrepresents the change in fair value of the contracts during the period.

 

TheTrust currently limits the amount of forecast production that can be hedged toa maximum 50 per cent with the remaining 50 per cent of production being soldat market prices.  The following table isan indicative summary of the Trust’s positions for crude oil, natural gas andrelated foreign exchange for the next twelve months as at December 31,2008.

** **

**Table 13**

 

**Hedge PositionsAs at December 31, 2008 ****(1)(2)**

 
| ** **           | ** **   | **Q1 2009**  | ** **   | **Q2 2009** | ** **   | **Q3 2009**  | ** **   | **Q4 2009** | ** **   |
|----------------------|--------------|-------------------|--------------|------------------|--------------|-------------------|--------------|------------------|--------------|
| **Crude Oil**   | ** **   | **US$ /bbl** | ** **   | **bbl/day**      | ** **   | **US$ /bbl** | ** **   | **bbl/day**      | ** **   | **US$ /bbl** | ** ** | **bbl/day** | ** ** | **US$ /bbl** | ** ** | **bbl/day** | ** ** |
| Sold Call            |         | —            |         | —           |         | —            |         | —           |         | — |   | — |   | — |   | — |   |
| ***Bought Put***     | *** *** | ***55.00***       | *** *** | ***2,500***      | *** *** | ***55.00***       | *** *** | ***2,500***      | *** *** | ***55.00*** | *** *** | ***2,500*** | *** *** | ***55.00*** | *** *** | ***2,500*** | *** *** |
| Sold Put             |         | 40.00             |         | 2,500            |         | 40.00             |         | 2,500            |         | 40.00 |   | 2,500 |   | 40.00 |   | 2,500 |   |
| ** **           | ** **   | ** **        | ** **   | ** **       | ** **   | ** **        | ** **   | ** **       | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| **Natural Gas** | ** **   | **Cdn$/GJ**       | ** **   | **GJ/day**       | ** **   | **Cdn$/GJ**       | ** **   | **GJ/day**       | ** **   | **Cdn$/GJ** | ** ** | **GJ/day** | ** ** | **Cdn$/GJ** | ** ** | **GJ/day** | ** ** |
| Sold Call            |         | 10.76             |         | 62,202           |         | 8.00              |         | 20,000           |         | 8.00 |   | 20,000 |   | 8.00 |   | 20,000 |   |
| ***Bought Put***     | *** *** | ***8.17***        | *** *** | ***62,202***     | *** *** | ***6.50***        | *** *** | ***20,000***     | *** *** | ***6.50*** | *** *** | ***20,000*** | *** *** | ***6.50*** | *** *** | ***20,000*** | *** *** |
| Sold Put             |         | 4.50              |         | 20,000           |         | 4.50              |         | 20,000           |         | 4.50 |   | 20,000 |   | 4.50 |   | 20,000 |   |

 

----

(1)       The prices and volumes noted above represents averages for severalcontracts and the average price for the portfolio of options listed above doesnot have the same payoff profile as the individual option contracts. Viewingthe average price of a group of options is purely for indicative purposes. Thenatural gas price shown translates all NYMEX positions to an AECO equivalentprice.  In addition to positions shownhere, ARC has entered into additional basis positions.

(2)       Please refer to note 13 in the Notes to the Consolidated FinancialStatements for full details of the Trust’s hedging positions as of December 31,2008.

 

Table13 should be interpreted as follows using the first quarter 2009 natural gashedges as an example. To accurately analyze the Trust’s hedge position,contracts need to be modeled separately as using average prices and volumes maybe misleading.

 

·      If the market price is below $4.50, ARC will receive $8.17 less thedifference between $4.50 and the market price on 20,000 GJ per day.  For example if the market price is $4.45, theTrust will receive $8.12 on 20,000 GJ per day.

·      If the market price is between $4.50 and $8.17, ARC will receive $8.17on 62,202 GJ per day.

·      If the market price is between $8.17 and $10.76, ARC will receive themarket price on 62,202 GJ per day.

·      If the market price exceeds $10.76, ARC will receive $10.76 on 62,202GJ per day.

 

10

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**Operating Netbacks**

 

The Trust’s operating netback, before realized hedging gains and losses,increased 37 per cent to $47.75 per boe in 2008 compared to $34.82 per boe in2007. The increase in netbacks in 2008 is as a result of the significantincrease in revenue per boe that was partially offset by increased costs forroyalties, operating costs and transportation costs.

 

The Trust’s 2008 netback, after realized hedging gains and losses,decreased to $44.58 per boe as a result of losses recorded on the Trust’s crudeoil and natural gas contracts during the year of $3.17 per boe compared to asmall gain of $0.62 per boe recorded in 2007 that increased the 2007 netback to$35.44 per boe.

 

The components of operating netbacks are summarizedin Table 14:

 

**Table 14**

 
| **Netbacks  ($ per boe)**                | ** ** | **Crude Oil  ($ /bbl)** | ** ** | **Heavy Oil  ($ /bbl)** | ** ** | **Gas  ($ /mcf)** | ** ** | **NGL  ($ /bbl)** | ** ** | **2008 Total  ($ /boe)** | ** ** | **2007 Total  ($ /boe)** | ** ** |
|----------------------------------------------------|------------|-----------------------------------|------------|-----------------------------------|------------|------------------------|------------|------------------------|------------|------------------------------------|------------|------------------------------------|------------|
| Weighted average sales price                       |       | 94.97                             |       | 77.85                             |       | 8.58                   |       | 69.71                  | ** ** | **71.25**                          |       | 54.54                              |       |
| Other revenue                                      |       | —                            |       | —                            |       | —                 |       | —                 | ** ** | **0.34**                           | ** ** | 0.13                               |       |
| Total revenue                                      |       | 94.97                             |       | 77.85                             |       | 8.58                   |       | 69.71                  |       | **71.59**                          | ** ** | 54.67                              |       |
| Royalties                                          |       | (14.58                            | )          | (8.41                             | )          | (1.82                  | )          | (19.58                 | )          | **(12.91**                         | **)**      | (9.59                              | )          |
| Transportation                                     |       | (0.14                             | )          | (1.17                             | )          | (0.24                  | )          | —                 |       | **(0.80**                          | **)**      | (0.72                              | )          |
| Operating costs(1)                                 |       | (13.91                            | )          | (11.63                            | )          | (1.19                  | )          | (8.22                  | )          | **(10.13**                         | **)**      | (9.54                              | )          |
| Netback prior to hedging                           |       | 66.34                             |       | 56.64                             |       | 5.33                   |       | 41.91                  |       | **47.75**                          | ** ** | 34.82                              |       |
| Realized gain (loss) on risk management  contracts |       | (7.03                             | )          | —                            |       | (0.16                  | )          | —                 |       | **(3.17**                          | **)**      | 0.62                               |       |
| Netback after hedging                              |       | 59.31                             |       | 56.64                             |       | 5.17                   |       | 41.91                  |       | **44.58**                          | ** ** | 35.44                              |       |

 

----

(1)       Operating expenses are composed of direct costs incurred to operate oiland gas wells. A number of assumptions have been made in allocating these costsbetween oil, heavy oil, natural gas and natural gas liquids production.

 

Royaltiesas a percentage of pre-hedged commodity revenue net of transportation wererelatively unchanged at 18.2 per cent ($12.91 per boe) in 2008 compared to 17.8per cent ($9.59 per boe) in 2007. The Trust’s typical royalty rate has beenapproximately 18 per cent on a consolidated basis.  Going forward into 2009, the Trust expects tosee more volatility in the royalty rates as a result of the Alberta Government’sNew Royalty Framework. For additional information, see “Alberta Government NewRoyalty Framework”.

 

Operatingcosts increased to $10.13 per boe in 2008 compared to $9.54 per boe in 2007.Total operating costs increased $23.1 million, or 11 per cent in 2008. Theincreased costs were in line with guidance and reflect the additional costsassociated with the approximately 300 new wells brought on stream during 2008.There is a high fixed operating cost component for the Trust’s propertiesresulting in a trend of increased operating costs on a per boe basis as theproperties’ production declines over time. The Trust estimates that full year2009 operating costs will be approximately $250 million or approximately $10.70per boe based on annual production of approximately 64,000 to 65,000 boe perday.  This includes a six per centincrease for costs associated with new drills in 2009.

 

**Alberta Government New Royalty Framework**

 

On April 10, 2008, theAlberta Government announced revisions to the New Royalty Framework(“Framework” or “NRF”).  The Frameworkwas legislated in November 2008 and took effect on January 1, 2009.

 

11

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The revisions to the Framework include the following:

 

·      Increased royalty rates on conventional and non-conventional oil andnatural gas production in Alberta whereby royalty rates may increase to maximumrates of 50 per cent;

·      Sliding scale royalty calculations based on a broader range of commodityprices whereby conventional oil and natural gas royalty rates may increase upto maximum prices of approximately Cdn$120 per barrel and Cdn$16 per GJ,respectively;

·      The elimination of royalty incentive and royalty holiday programs withthe exception of specific programs relating to deep oil and natural gasdrilling programs, innovative technology and enhanced recovery programs.

 

Subsequent to legislation of the NRF, the Alberta Government introducedthe Transitional Royalty Plan (“TRP”) in response to the anticipated decreasein Alberta development activity resulting from the economic downturn anddeclining commodity prices.  The TRPoffers reduced royalty rates for new wells drilled on or afterNovember 19, 2008 that meet certain depth criteria.  The TRP is in place for a maximum period offive years to December 31, 2013; all wells will convert to the NRF onJanuary 1, 2014.  The TRP is an“elective plan” whereby an election must be filed on an individual well basisto qualify for the TRP.  The Trust doesnot anticipate a significant benefit from the TRP in 2009 as the majority ofthe Trust’s wells converted to the NRF on January 1, 2009.

 

Approximately 65 per cent ofthe Trust’s production is in Alberta; consequently, the Framework will have asignificant impact on the Trust’s Alberta and corporate royalty rates. TheTrust has completed an assessment of the Framework and has estimated that theTrust’s average corporate royalty rate will change from approximately 18 percent of revenue in 2008 to between 17 and 26 per cent of revenue in 2009depending upon fluctuating commodity prices as illustrated in Table 15.

 

**Table 15**

 

**Royalty Rates – New RoyaltyFramework**

 
| Edmonton posted oil (Cdn/$/bbl) (1)                            | ** ** | **$**   | **40**    | ** ** | **$**  | **60**   | ** ** | **$**  | **80**   | ** ** | **$** | **100**   | ** ** |
|----------------------------------------------------------------|------------|---------|-----------|------------|--------|----------|------------|--------|----------|------------|-------|-----------|------------|
| AECO  natural gas (Cdn$/GJ) (1)                                | ** ** | **$**   | **6**     | ** ** | **$**  | **6**    | ** ** | **$**  | **8**    | ** ** | **$** | **10**    | ** ** |
|                                                           |       |    |      |       |   |     |       |   |     |
| Current Alberta royalty rate (2)                               |       | 17.5    | %         | 17.5       | %      | 17.5     | %          | 17.5   | %        |
| NRF Alberta royalty rate (3)                                   |       | 15.5    | %         | 20.0       | %      | 25.0     | %          | 29.0   | %        |
| **% increase (decrease) - Alberta royalty  rate**              | ** ** | **(10** | **)%**    | **14**     | **%**  | **43**   | **%**      | **66** | **%**    |
| Current Corporate royalty rate (2)                             |       | 18.0    | %         | 18.0       | %      | 18.0     | %          | 18.0   | %        |
| NRF Corporate royalty rate (3)                                 |       | 17.0    | %         | 20.0       | %      | 23.0     | %          | 26.0   | %        |
| **% increase (decrease) - Corporate royalty  rate**            | ** ** | **(6**  | **)%**    | **11**     | **%**  | **28**   | **%**      | **44** | **%**    |
| Increase (decrease) in annual Corporate  royalties ($Millions) | ** ** | **$**   | **(10.0** | **)**      | **$**  | **15.0** | ** ** | **$**  | **60.0** | ** ** | **$** | **125.0** | ** ** |
| Decrease (increase) annual cash flow per  unit                 | ** ** | **$**   | **(0.05** | **)**      | **$**  | **0.07** | ** ** | **$**  | **0.27** | ** ** | **$** | **0.58**  | ** ** |

 

----

(1)       Canadian dollar denominated prices before quality differentials.

(2)       Current Alberta and Corporate royalty rates are consistent across allprice scenarios as price ceilings have been exceeded under the current royaltyregime whereby royalty rates change only marginally across the price scenariospresented.

(3)       Estimated royalty rates based on guidelines that are subject tointerpretation. Royalty rate includes Crown, Freehold and Gross Overrideroyalties for all jurisdictions in which the Trust operates.

 

12

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Table 16 illustrates provincialroyalty rates following implementation of the Framework in Alberta.  At low prices, royalty rates will be lower inAlberta, while at moderate to high prices royalty rates will be higher inAlberta than in the Trust’s other operating jurisdictions.  Approximately 65 per cent of production comesfrom Alberta, 22 per cent from Saskatchewan and 11 per cent from BritishColumbia and one per cent from Manitoba. The Trust will continue to evaluateprojects on the basis of each province’s fiscal regime as well as technicalmerits and direct its future investment spending to the most economicallyfavorable projects.

 

**Table 16**

 

**Provincial Royalty Rates – NewRoyalty Framework**

 
| Edmonton posted oil (Cdn/$/bbl) (1)      | ** ** | **$**    | **40** | ** ** | **$**  | **60**   | ** ** | **$**    | **80** | ** ** | **$** | **100** | ** ** |
|------------------------------------------|------------|----------|--------|------------|--------|----------|------------|----------|--------|------------|-------|---------|------------|
| AECO  natural gas (Cdn$/GJ) (1)          | ** ** | **$**    | **6**  | ** ** | **$**  | **6**    | ** ** | **$**    | **8**  | ** ** | **$** | **10**  | ** ** |
|                                     |       |     |   |       |   |     |       |     |   |
| Current Alberta royalty rate (2)         |       | 17.5     | %      | 17.5       | %      | 17.5     | %          | 17.5     | %      |
| **NRF Alberta royalty rate****(3)**      | ** ** | **15.5** | **%**  | **20.0**   | **%**  | **25.0** | **%**      | **29.0** | **%**  |
| **Saskatchewan royalty rate****(2)**     | ** ** | **20.7** | **%**  | **20.7**   | **%**  | **20.7** | **%**      | **20.7** | **%**  |
| **British Columbia royalty rate****(2)** | ** ** | **23.5** | **%**  | **23.5**   | **%**  | **23.5** | **%**      | **23.5** | **%**  |
| **Manitoba royalty rate****(2)**         | ** ** | **17.4** | **%**  | **17.4**   | **%**  | **17.4** | **%**      | **17.4** | **%**  |

 

----

(1)       Canadian dollar denominated prices before quality differentials.

(2)       Royalty rate includes Crown, Freehold and Gross Override royalties forall jurisdictions in which the Trust operates.

 

As royalties under the new Framework are sensitive to both commodityprices and production levels, the estimated NRF Alberta and corporate royaltyrates will fluctuate with commodity prices, well production rates, productiondecline of existing wells, and performance and location of new wells drilled.

 

The Trust completed an upgradeto its production accounting system in the fourth quarter of 2008 toaccommodate royalty calculations and reporting requirements under the Frameworkeffective January 1, 2009.

 

**General and Administrative Expenses and Trust Unit IncentiveCompensation**

 

G&A net of overhead recoveries on operated properties increasedseven per cent to $38.8 million in 2008 from $36.3 million in 2007. Increasesin G&A expenses for 2008 were a result of increased staff costs based on asix per cent increase in the staff levels on average in 2008 due to higherlevels of activity.

 

The Trust paid out $28.2 million under the Whole Trust Unit IncentivePlan (“Whole Unit Plan”) in 2008 compared to $12.7 million in 2007 ($21.3million and $9.6 million of the payouts were allocated to G&A in 2008 and2007, respectively, and the remainder to operating costs and property, plantand equipment).  The increase in paymentsduring 2008 was a result of having two different performance unit grants vestduring the year as compared to only one grant that vested in 2007.  The next cash payments under the Whole UnitPlan are scheduled to occur in March and September 2009.

 

13

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Table 17 is a breakdown of G&A and trust unitincentive compensation expense:

 

**Table 17**

 
| **G&A and Trust Unit Incentive Compensation Expense  ($ millions except per boe)** | ** ** | **2008**  | ** ** | **2007**  | ** ** | **% Change** | ** ** |
|------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------|------------|-----------|------------|-------------------|------------|
| G&A expenses                                                                                                                         | ** ** | **55.6**  | ** ** | **52.7**  | ** ** | **6**             | ** ** |
| Operating recoveries                                                                                                                     | ** ** | **(16.8** | **)**      | **(16.4** | **)**      | **2**             | ** ** |
| Cash G&A expenses before Whole Unit  Plan                                                                                            | ** ** | **38.8**  | ** ** | **36.3**  | ** ** | **7**             | ** ** |
| Cash Expense – Whole Unit Plan                                                                                                      | ** ** | **21.3**  | ** ** | **9.6**   | ** ** | **122**           | ** ** |
| Cash G&A expenses including Whole Unit  Plan                                                                                         | ** ** | **60.1**  | ** ** | **45.9**  | ** ** | **31**            | ** ** |
| Accrued compensation - Whole Unit Plan                                                                                                   | ** ** | **1.1**   | ** ** | **3.2**   | ** ** | **(66**           | **)**      |
| Total G&A and trust unit incentive  compensation expense                                                                             | ** ** | **61.2**  | ** ** | **49.1**  | ** ** | **25**            | ** ** |
| Total G&A and trust unit incentive  compensation expense per boe                                                                     | ** ** | **2.57**  | ** ** | **2.15**  | ** ** | **20**            | ** ** |

 

A non-cash trust unit incentivecompensation expense (“non-cash compensation expense”) of $1.1 million ($0.05per boe) was recorded in 2008 compared to $3.2 million ($0.14 per boe) in 2007.This non-cash amount relates to estimated costs of the Whole Unit Plan toDecember 31, 2008.

 

**Whole Unit Plan**

 

In March 2004, the Board of Directors approved a new Whole UnitPlan to replace the Rights Plan for new awards granted subsequent to the firstquarter of 2004. The new Whole Unit Plan results in employees, officers anddirectors (the “plan participants”) receiving cash compensation in relation tothe value of a specified number of underlying units. The Whole Unit Planconsists of Restricted Trust Units (“RTUs”) for which the number of units isfixed and will vest over a period of three years and Performance Trust Units(“PTUs”) for which the number of units is variable and will vest at the end ofthree years.

 

Upon vesting, the planparticipant is entitled to receive a cash payment based on the fair value ofthe underlying trust units plus accrued distributions. The cash compensationissued upon vesting of the PTUs is dependent upon the performance of the Trustcompared to its peers and indicated by the performance multiplier. Theperformance multiplier is based on the percentile rank of the Trust’s totalunitholder return compared to its peers. Total return is calculated as the sumof the change in the market price of the trust units in the period plus theamount of distributions in the period. The performance multiplier ranges fromzero, if ARC’s performance ranks in the bottom quartile, to two for topquartile performance.

 

14

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Table 18 shows the changes during the year of RTUs and PTUsoutstanding:

 

**Table 18**

 
| **Whole Unit Plan  (units in thousands and $ millions except per unit)** | ** ** | **Number of  RTUs** | ** ** | **Number of  PTUs** | ** ** | **Total  RTUs and PTUs** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------|------------|--------------------------|------------|--------------------------|------------|------------------------------------|------------|
| Balance,  beginning of year                                                                                                |       | 746                      |       | 903                      |       | 1,649                              |       |
| Granted  in the year                                                                                                       |       | 403                      |       | 352                      |       | 755                                |       |
| Vested  in the year                                                                                                        |       | (347                     | )          | (252                     | )          | (599                               | )          |
| Forfeited  in the year                                                                                                     |       | (46                      | )          | (44                      | )          | (90                                | )          |
| Balance,  end of year (1)                                                                                                  |       | 756                      |       | 959                      |       | 1,715                              |       |
| Estimated  distributions to vesting date (2)                                                                               |       | 197                      |       | 328                      |       | 525                                |       |
| Estimated  units upon vesting after distributions                                                                          |       | 953                      |       | 1,287                    |       | 2,240                              |       |
| Performance  multiplier (3)                                                                                                |       | —                   |       | 1.6                      |       | —                             |       |
| Estimated  total units upon vesting                                                                                        |       | 953                      |       | 2,110                    |       | 3,063                              |       |
| Trust  unit price at December 31, 2008                                                                                |       | $                        | 20.10      |                     | $          | 20.10                              |       | $ | 20.10 |   |
| Estimated  total value upon vesting                                                                                        |       | 19.2                     |       | 42.4                     |       | 61.6                               |       |
|                                                                                                                            |            |                          |            |                          |            |                                    |            |  |  |  |

 

----

(1)                      Based on underlying units before performancemultiplier and accrued distributions.

(2)                      Represents estimated additional units to beissued equivalent to estimated distributions accruing to vesting date.

(3)                      The performance multiplier only applies toPTUs and was estimated to be 1.6 at December 31, 2008 based on an averagefor all outstanding grants. The performance multiplier is assessed each periodend based on actual results of the Trust relative to its peers.

 

The value associated withthe RTUs and PTUs is expensed in the statement of income over the vestingperiod with the expense amount being determined by the trust unit price, thenumber of PTUs to be issued on vesting, and distributions. Therefore, theexpense recorded in the statement of income fluctuates over time.

 

Table 19 is a summary of the range of future expected payments underthe Whole Unit Plan based on variability of the performance multiplier:

 

**Table 19**

 
| **Value of Whole Unit Plan as at December 31, 2008** | ** ** | **Performance multiplier** | ** ** |
|---------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| **(units thousands and $ millions except per unit)**           | ** ** | **-**                           | ** ** | **1.0** | ** ** | **2.0** | ** ** |
| Estimated  trust units to vest                                                                    |       |                            |       |   |   |   |   |
| RTUs                                                                                              |       | 953                             |       | 953 |   | 953 |   |
| PTUs                                                                                              |       | —                          |       | 1,287 |   | 2,575 |   |
| **Total units****(1)**                                                                            | ** ** | **953**                         | ** ** | **2,240** | ** ** | **3,528** | ** ** |
| Trust  unit price (2)                                                                             |       | $                               | 20.10      |   | $ | 20.10 |   | $ | 20.10 |   |
| Trust  unit distributions per month (2)                                                           |       | $                               | 0.15       |   | $ | 0.15 |   | $ | 0.15 |   |
| **Value of Whole Unit Plan upon vesting****(3)**                                                  | ** ** | **$**                           | **19.2**   | ** ** | **$** | **45.0** | ** ** | **$** | **70.9** | ** ** |
| 2009                                                                                              |       | 9.0                             |       | 16.1 |   | 23.3 |   |
| 2010                                                                                              |       | 6.7                             |       | 16.1 |   | 25.4 |   |
| 2011                                                                                              |       | 3.5                             |       | 12.8 |   | 22.2 |   |

 

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(1)                    Includes additional estimated units to beissued for accrued distributions to vesting date.

(2)                    Values will fluctuate over the vesting periodbased on the volatility of the underlying trust unit price and distributionlevels. Assumes a future trust unit price of $20.10 and $0.15 per trust unitdistributions based on the unit price and distribution levels in place at December 31,2008.  Subsequent to year-end, thedistribution level decreased to $0.12 per trust unit.

(3)                    Upon vesting, a cash payment is madeequivalent to the value of the underlying trust units. The payment is made onvesting dates in March and September of each year and at that time isreflected as a reduction of cash flow from operating activities.

 

15

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Due to the variability inthe future payments under the plan, the Trust estimates that between $19.2million and $70.9 million will be paid out from 2009 through 2011 based on thecurrent trust unit price, distribution levels and the Trust’s market performancerelative to its peers.

 

**Provision for Non-recoverable Accounts Receivable**

 

The Trust recorded aprovision for non-recoverable accounts receivable of $32 million ($23.9 millionnet of tax) in 2008 (nil in 2007).  In July 2008,SemCanada Crude (“SemCanada”), a counterparty that marketed a portion of theTrust’s production filed for protection under the Companies’ CreditorsArrangement Act (“CCAA”).  SemCanada’sparent company had continuously rated as investment grade credit by an externalrating agency up until 10 days prior to filing for credit protection in theUnited States.  The Trust’s totalexposure to SemCanada was $30.6 million. Due to uncertainty surrounding the ultimate recoverable amount andexpected timing of recovery, the Trust recorded a provision for the fullSemCanada receivable of $30.6 million in 2008. In addition, the Trust recorded a provision of $1.4 million for sixadditional counterparties that also filed for CCAA protection during 2008 or wereexperiencing financial distress.   TheTrust’s allowance for doubtful accounts was $32 million as at December 31,2008 (nil as at December 31, 2007).

 

**Interest Expense**

 

Interest expense decreasedto $32.9 million in 2008 from $36.9 million in 2007 due to a decrease inshort-term interest rates. As at December 31, 2008, the Trust had $901.6million of debt outstanding, of which $259.6 million was fixed at a weightedaverage rate of 5.1 per cent and $642.2 million, including the working capitalfacility, was floating at current market rates plus a credit spread of 60 basispoints. Fifty-five per cent (US $408.5 million) of the Trust’s debt isdenominated in U.S. dollars.

 

**Foreign Exchange Gains and Losses**

 

The Trust recorded a loss of $89.4 million ($3.76 per boe) in 2008 onforeign exchange transactions compared to a gain of $69.4 million ($3.03 perboe) in 2007. These amounts include both realized and unrealized foreignexchange gains and losses.

 

Unrealized foreign exchange gains and losses are due to revaluation ofU.S. denominated debt balances. The volatility of the Canadian dollar duringthe reporting period has a direct impact on the unrealized component of theforeign exchange gain or loss. The unrealized gain/loss impacts net income butdoes not impact cash flow from operating activities as it is a non-cash amount.From December 31, 2007 to December 31, 2008, the Cdn$/US$ exchangerate has increased from 1.01 to 1.22 creating an unrealized loss of $90.8million on U.S. dollar denominated debt.

 

Realized foreign exchange gains or losses arise from U.S. denominatedtransactions such as interest payments, debt repayments and hedgingsettlements.  Included in the 2008realized foreign exchange gain was a gain of $2.3 million relating, in part, toa repayment of US$6 million of debt in October 2008. The debt was issuedin 2002 when the Cdn$/US$ foreign exchange rate was approximately 1.56 andstrengthened considerably to 1.04 on repayment in 2008.

 

16

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**Taxes**

 

In 2008, a future income taxrecovery of $4.5 million was included in income compared to $121.3 million in2007. The future income tax recovery in 2007 included the impact of alegislated reduction in the future corporate income tax rates in the fourthquarter of 2007 whereby the Trust’s expected future corporate income tax ratedecreased from 29.4 per cent to 25.8 per cent after the rate reduction.  In 2008, the Trust’s expected futurecorporate income tax rate decreased marginally, creating a recovery of $4.5million for the year.

 

At December 31, 2008,the Trust and the Trust’s subsidiaries had tax pools of approximately $2.1billion. The tax pools consist of $1.8 billion of tangible and intangiblecapital assets, $86.9 million of non-capital loss carry-forwards that expire atvarious periods to 2026, and $213.1 million of other tax pools. Included in theabove tax basis are the Trust’s tax pools of approximately $590.2 million.

 

On June 22, 2007, thefederal legislation (Bill C-52) implementing the tax on publicly traded incometrusts and limited partnerships (the “SIFT Rules”) received Royal Assent.  The SIFT Rules are not expected toeffect the Trust until 2011 provided the Trust does not exceed the normalgrowth guidelines announced by the Department of Finance.  Subsequent to the Trust’s equity issuancethat closed on February 6, 2009, the Trust may now increase its equity byapproximately $5.1 billion between now and 2011 without exceeding the normalgrowth guidelines. The Trust does not anticipate that the normal growthguidelines will impair the Trust’s ability to annually replace or grow reservesin the next two years as the guidelines allow sufficient growth targets.

 

On February 26, 2008the Minister of Finance announced as part of the federal budget that theprovincial component of the tax on the Trust is to be calculated based on thegeneral provincial rate in each province in which the Trust has a permanentestablishment.  This is the same way acorporation would calculate its provincial tax rate, however it is differentthan the Provincial tax component included in the SIFT Rules, which currentlyprovide for a deemed rate of 13 per cent. At December 31, 2008 the Trust has used the deemed 13 per centprovincial rate to calculate its future income taxes as the proposedlegislation had not been issued for calculating the provincial rate.  On February 1, 2009 the Minister ofFinance tabled a Notice of Ways and Means that includes the proposedlegislation for calculating the provincial tax rate.

 

On November 28, 2008the Minister of Finance introduced legislation to facilitate the conversion ofexisting income trusts into corporations. In general, the proposed legislation will permit a conversion to be taxdeferred for both the unitholders and the income trust.  Due to Parliament being prorogued on December 4,2008 this proposed legislation essentially expired.  On February 1, 2009 the Minister ofFinance tabled a Notice of Ways and Means that includes the proposedlegislation to facilitate the conversion of existing income trusts into corporations.

 

Management and the Board ofDirectors continue to review the impact of the SIFT Rules on our businessstrategy and while there has not been a decision as to ARC’s future directionat this time we are of the opinion that the conversion from a trust to acorporation may be the most logical and tax efficient alternative for ARCunitholders. ARC expects future technical interpretations and details willfurther clarify the legislation. Canadian investors who

 

17

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hold their units in ataxable account will be relatively indifferent on an after tax basis as towhether ARC is structured as a corporation or as a Trust in 2011. However, Canadian tax deferred investors (those holding their Trust Units in atax deferred vehicle such as an RRSP, RRIF or pension plan) and foreigninvestors will realize a lower return on distributions in 2011 due to theintroduction of the SIFT Tax should ARC stay as a Trust and their inability toclaim the dividend tax credit if ARC converts to a corporation.

 

The corporate income taxrate applicable to 2008 is 29.5 per cent, however the Trust and itssubsidiaries did not pay any material cash income taxes for fiscal 2008. Due tothe Trust’s structure, currently, both income tax and future tax liabilitiesare passed on to the unitholders by means of royalty payments made between ARCResources and the Trust.

 

**Depletion, Depreciation and Accretion of Asset RetirementObligation**

 

The depletion, depreciation and accretion (“DD&A”) rate decreasedto $15.88 per boe in 2008 from $16.23 per boe in 2007. The lower DD&A ratewas driven by an increase in the Trust’s proved reserves.

 

A breakdown of the DD&A rate is summarized in Table 20:

 

**Table 20**

 
| **DD&A Rate  ($ millions except per boe amounts)** | ** ** | **2008**  | ** ** | **2007** | ** ** | **% Change** | ** ** |
|--------------------------------------------------------------------------------------|------------|-----------|------------|----------|------------|-------------------|------------|
| Depletion  of oil & gas assets (1)                                          | ** ** | **370.3** |       | 360.0    |       | 3                 |       |
| Accretion  of asset retirement obligation (2)                                        | ** ** | **9.3**   |       | 11.5     |       | (19               | )          |
| Total  DD&A                                                                      | ** ** | **379.6** |       | 371.5    |       | 2                 |       |
| DD&A  rate per boe                                                               | ** ** | **15.88** |       | 16.23    |       | (2                | )          |

 

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(1)                     Includes depletion of the capitalized portionof the asset retirement obligation that was capitalized to the PP&E balanceand is being depleted over the life of the reserves.

(2)                     Represents the accretion expense on the assetretirement obligation during the year.

 

**Goodwill**

 

The goodwill balance of $157.6 million arose as a result of theacquisition of Star Oil and Gas in 2003. The goodwill balance was determinedbased on the excess of total consideration paid plus the future income taxliability less the fair value of the assets, for accounting purposes, acquiredin the transaction.

 

Accounting standards require that the goodwill balance be assessed forimpairment at least annually or more frequently if events or changes incircumstances indicate that the balance might be impaired. If such impairmentexists, it would be charged to income in the period in which the impairmentoccurs. The Trust has determined that there was no goodwill impairment as of December 31,2008.

 

**Capital Expenditures and Net Acquisitions**

 

Total capital expenditures, excluding acquisitions and dispositions,totaled $548.6 million in 2008 compared to $397.2 million in 2007. This amountwas incurred on drilling and completions, geological, geophysical andfacilities expenditures, and undeveloped land. The $122.4 million purchase ofundeveloped land in 2008 increased the Trust’s

 

18

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land holdings to 534,416 net acres that will provide drillingopportunities and, if successful, incremental future production and reserves.

 

In addition to capital expenditures on development activities, theTrust completed net property acquisitions of $51 million in 2008 of which $48.6million related to the acquisition of undeveloped land and is included in thenet acres quoted above.

 

Proved plus probable oil and gas reserves increased 12 per cent to321.7 million boe at year-end 2008 as a result of the Trust’s 2008 capitalexpenditure program.

 

A breakdown of capital expenditures and net acquisitions is shown inTable 21:

 

**Table 21**

 
| **Capital Expenditures  ($ millions)**    | ** ** | **2008**  | ** ** | **2007** | ** ** | **% Change** | ** ** |
|-----------------------------------------------------|------------|-----------|------------|----------|------------|-------------------|------------|
| Geological  and geophysical                         | ** ** | **27.1**  |       | 14.9     |       | 82                |       |
| Drilling  and completions                           | ** ** | **305.4** |       | 229.5    |       | 33                |       |
| Plant  and facilities                               | ** ** | **90.4**  | ** ** | 72.1     |       | 25                |       |
| Undeveloped  land purchased at crown land sales     | ** ** | **122.4** | ** ** | 77.5     |       | 58                |       |
| Other  capital                                      | ** ** | **3.3**   | ** ** | 3.2      |       | 3                 |       |
| Total  capital expenditures before net acquisitions | ** ** | **548.6** | ** ** | 397.2    |       | 38                |       |
| Producing  property acquisitions (1)                | ** ** | **1.4**   | ** ** | 47.1     |       | (97               | )          |
| Undeveloped  land property acquisitions             | ** ** | **53.5**  | ** ** | —   |       | 100               |       |
| Producing  property dispositions(1)                 | ** ** | **(0.2**  | **)**      | (4.6     | )          | (96               | )          |
| Undeveloped  land property dispositions             | ** ** | **(3.7**  | **)**      | —   |       | 100               |       |
| Total  capital expenditures and net acquisitions    | ** ** | **599.6** | ** ** | 439.7    |       | 36                |       |

 

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(1)                      Value is net of post-closing adjustments.

 

Approximately 68 per cent of the $548.6 million capital program wasfinanced with cash flow from operating activities in 2008 compared to 49 percent in 2007. Property acquisitions were financed through debt and workingcapital.

 

**Table 22**

 

**Source ofFunding of Capital Expenditures and Net Acquisitions**

($millions)

 
| ** **                           | ** ** | **2008**                 | ** ** | **2007**              | ** ** |
|--------------------------------------|------------|--------------------------|------------|-----------------------|------------|
| ** **                           | ** ** | **Development  Capital** | ** ** | **Net  Acquisitions** | ** ** | **Total  Expenditures** | ** ** | **Development  Capital** | ** ** | **Net  Acquisitions** | ** ** | **Total  Expenditures** | ** ** |
| Expenditures                         | ** ** | **548.6**                | ** ** | **51.0**              | ** ** | **599.6** | ** ** | 397.2 |   | 42.5 |   | 439.7 |   |
| **Per cent funded by:**              |       |                     |       |                  |       |   | ** ** |   |   |   |   |   |   |
| Cash  flow from operating activities | ** ** | **68**                   | **%**      | **—**            | ** ** | **62** | **%** | 49 | % | — |   | 44 | % |
| Proceeds  from DRIP and Rights Plan  | ** ** | **23**                   | **%**      | **—**            | ** ** | **21** | **%** | 28 | % | — |   | 25 | % |
| Debt                                 | ** ** | **9**                    | **%**      | **100**               | **%**      | **17** | **%** | 23 | % | 100 | % | 31 | % |
| ** **                           | ** ** | **100**                  | **%**      | **100**               | **%**      | **100** | **%** | 100 | % | 100 | % | 100 | % |

 

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ARC announced a $450 millioncapital expenditure budget for 2009 funding a combination of annual productionreplacement and future growth development including the development of a 60mmcf per day gas plant in the Dawson area to be operational in early 2010.  The Trust will continually monitor thecapital expenditure program in the context of the current economic conditionsand make any necessary modifications to the planned expenditures as required.

 

**Long-TermInvestment**

 

During the second quarter of2007, the Trust sold its investment in the shares of a private company that wasinvolved in the acquisition of oil sands leases. The transaction closed on June 25,2007. The Trust recorded a cash gain of $13.3 million with total proceeds of$33.3 million recorded as part of cash flow from investing activities. Theinvestment in the shares of the private company was considered to be a relatedparty transaction due to common directorships of the Trust, the private companyand the manager of a private equity fund that held shares in the privatecompany. In addition, certain directors and officers of the Trust had minordirect and indirect shareholdings in the private company.

 

**Asset Retirement Obligation and Reclamation Fund**

 

At December 31, 2008, the Trust recorded an Asset RetirementObligation (“ARO”) of $141.5 million ($140 million at December 31, 2007)for future abandonment and reclamation of the Trust’s properties. The estimatedARO includes assumptions in respect of actual costs to abandon wells or reclaimthe property as well as annual inflation factors in order to calculate theundiscounted total future liability. The undiscounted total future liabilitywas unchanged at $1.3 billion at December 31, 2008 and 2007.  A significant portion of the costs areprojected to be incurred in years 2049 to 2059.

 

Included in the December 31, 2008 ARO balance was a $4.6 millionincrease related to development activities in 2008 as well as minor changes inmanagement’s estimate of the existing liabilities.  The ARO liability was also increased by $9.3million for accretion expense in 2008 ($11.5 million in 2007) and was reducedby $12.4 million ($18.2 million in 2007) for actual abandonment expendituresincurred in 2008.

 

As a result of the Redwater acquisition in December 2005, theTrust set up a second reclamation fund (the “Redwater Fund”) in 2006 to fundfuture abandonment obligations attributed solely to the Redwater properties.The Trust makes annual contributions to the Redwater fund and may utilize thefunds only for abandonment activities for the Redwater property. With theaddition of the Redwater Fund, the Trust now maintains two reclamation fundsthat together held $28.2 million at December 31, 2008. Futurecontributions for the two funds will vary over time in order to provide for thetotal estimated future abandonment and reclamation costs that are to beincurred upon abandonment of the Trust’s properties.  Minimum contributions to the Redwater fundover the next 47 years will be approximately $91 million while the main fundhas no minimum contribution requirements.

 

In total, ARC contributed$11.7 million cash to its reclamation funds in 2008 ($12.1 million in 2007) andearned interest of $1.2 million ($1.4 million in 2007) on the fund balances.The fund balances were reduced by $10.7 million

 

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for cash-funded abandonmentexpenditures in 2008 ($18.1 million in 2007). Under the terms of the Trust’s investment policy, reclamation fundinvestments and excess cash can only be invested in Canadian or U.S. Governmentsecurities, investment grade corporate bonds, or investment grade short-termmoney market securities.

 

**Capitalization, Financial Resources and Liquidity**

 

A breakdown of the Trust’s capital structure is outlined in Table 23,as at December 31, 2008 and 2007:

 

**Table 23**

 
| **Capital Structure and Liquidity  ($ millions except per cent and ratio amounts)** | ** ** | **December 31, 2008** | ** ** | **December 31, 2007** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| Net  debt obligations (1)                                                                                                             | ** ** | **961.9**                       |       | 752.7                           |       |
| Market  value of trust units and exchangeable shares (2)                                                                              | ** ** | **4,405.9**                     |       | 4,349.3                         |       |
| Total  capitalization (3)                                                                                                             | ** ** | **5,367.8**                     |       | 5,102.0                         |       |
| Net  debt as a percentage of total capitalization                                                                                     | ** ** | **17.9**                        | **%**      | 14.8                            | %          |
| Net  debt to annualized YTD cash flow from operating activities                                                                       | ** ** | **1.0**                         |       | 1.1                             |       |

 

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(1)                      Net debt is a non-GAAP measure and iscalculated as long-term debt plus current liabilities less the current assetsas they appear on the Consolidated Balance Sheets.  Net debt excludes current unrealized amountspertaining to risk management contracts and the current portion of futureincome taxes.

(2)                      Calculated using the total trust unitsoutstanding at December 31 including the total number of trust unitsissuable for exchangeable shares at December 31 multiplied by the closingtrust unit price of $20.10 and $20.40 for 2008 and 2007, respectively.

(3)                      Total capitalization as presented does nothave any standardized meaning prescribed by Canadian GAAP and therefore it maynot be comparable with the calculation of similar measures for other entities.Total capitalization is not intended to represent the total funds from equityand debt received by the Trust.

 

The Trust’s current creditfacilities comprise US$212 million in senior secured notes currentlyoutstanding, a Cdn$800 million syndicated bank credit facility, of which $640.1million was outstanding at December 31, 2008 and a Cdn$25 million demandworking capital facility, of which $2.1 million was outstanding at December 31,2008.  On April 15, 2008 ARC extended the credit facility to April 2011under the same terms.  The creditfacility syndicate includes 11 domestic and international banks.  The Trust’s debt agreements contain a numberof covenants all of which were met as at December 31, 2008; theseagreements are available at www.SEDAR.com.  The major financial covenants aredescribed below:

 

·                  Long-term debt and letters of credit not toexceed three times annualized net income before non-cash items and interestexpense;

·                  Long-term debt, letters of credit, andsubordinated debt not to exceed four times annualized net income beforenon-cash items and interest expense; and

·                  Long-term debt and letters of credit not toexceed 50 per cent of the book value of unitholders’ equity and long-term debt,letters of credit, and subordinated debt.

 

As at December 31, 2008ARC has approximately $300 million of unused credit available: $160 millionunder its credit facility and the ability to issue an additional US$113 million(Cdn$140 million) of long-term notes under an agreement with one lender.  This option, which will expire in May 2009,unless renewed, would allow the Trust to

 

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issue long-term notes at arate equal to the related U.S. treasuries corresponding to the term of thenotes plus an appropriate credit risk adjustment at the time of issuance.

 

The $240 million of netproceeds from the equity offering that closed on February 6, 2009, wereused to reduce outstanding indebtedness under the Trust’s credit facility (seeUnitholders’ Equity).  This increased theTrust’s unused credit available to approximately $540 million including theoption of issuing US$113 million (Cdn$140 million) of U.S. dollar long-termnotes.

 

As a result of the weakenedglobal economic situation, the Trust along with all other oil and gas entitieswill have restricted access to capital and increased borrowing costs.   Although the Trust’s business and asset basehave not changed, the lending capacity of all financial institutions has beendiminished and risk premiums have increased. These issues will impact the Trust as it reviews financing alternativesfor the 2009 capital program, assesses potential future acquisitionopportunities and manages future cash flow decremented by lower commodityprices and higher borrowing costs.  TheTrust intends to finance its 2009 capital program with cash flow, existingcredit facilities, proceeds from the DRIP, potential asset dispositions and newborrowings or equity if necessary. Beyond that, the Trust may need to accessadditional capital and/or curtail capital expenditure plans and if so, willexecute the most cost effective and efficient means of financing its ongoingoperations.

 

**Unitholders’ Equity**

 

At December 31, 2008,there were 219.2 million trust units issued and issuable for exchangeableshares, an increase of six million trust units from December 31, 2007. Theincrease in number of trust units outstanding is mainly attributable to the 5.4million trust units issued pursuant to the DRIP during 2008 at an average priceof $22.61 per unit.

 

During 2008, the Trustissued 0.2 million trust units under the Trust Unit Incentive Rights Plan (“theRights Plan” for total proceeds of $4.2 million.  At December 31, 2008 there were norights outstanding as all rights issued under the plan have been exercised orcancelled.

 

Unitholders electing toreinvest distributions or make optional cash payments to acquire trust unitsfrom treasury under the DRIP may do so at a five per cent discount to theprevailing market price with no additional fees or commissions. During 2008,the Trust raised proceeds of $123.2 million and issued 5.4 million trust unitspursuant to the DRIP.

 

On January 21,2009 the Trust announced that it entered into an agreement, on a bought dealbasis, with a syndicate of underwriters for an offering of 13.5 million trustunits at $16.35 per trust unit, for gross proceeds of $220 million as well asan over-allotment option to purchase, on the same terms and conditions, up toan additional two million trust units. This option was exercised, in whole priorto closing of the offering on February 6, 2009. The gross proceeds raisedunder this offering were $253 million and proceeds net of underwriter andtransaction fees were approximately $240 million.  The proceeds were used to reduce outstandingindebtedness under the Trust’s credit facility.

 

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**Distributions**

 

ARC declared distributions of $570 million ($2.67 per unit),representing 60 per cent of 2008 cash flow from operating activities comparedto distributions of $498 million ($2.40 per unit) representing 71 per cent ofcash flow from operating activities in 2007.

 

As a result of thevolatility of oil prices throughout 2008, the Trust made several changes to themonthly distribution levels declared and paid to unitholders.  During the first seven months of 2008, oilprices soared to record high amounts causing the Trust to increase monthlydistributions to $0.28 per unit in order to meet the Trust’s objective oftransferring tax liabilities to unitholders and minimizing taxes paid by theTrust.  In the third quarter of 2008, oilprices decreased significantly causing the Trust to reduce distributions to$0.15 per unit.  Subsequent to year-end,the Trust further decreased distributions to $0.12 per unit in light of thecontinued weak commodity price environment.

 

The following items may bededucted from cash flow from operating activities to arrive at distributions tounitholders:

 

·                       The portion of capital expenditures that arefunded with cash flow from operating activities. In 2008, the Trust withheld 40per cent of 2008 cash flow from operating activities to fund 68 per cent of thecapital program excluding acquisitions and to make contributions to thereclamation funds. The remaining portion of capital expenditures was financedby proceeds from the DRIP program and debt.

 

·                       An annual contribution to the reclamationfunds, with $12.9 million being contributed in 2008 including interest earnedon the fund balances. The reclamation funds are segregated bank accounts orsubsidiary trusts and the balances will be drawn on in future periods as the Trustincurs abandonment and reclamation costs over the life of its properties.

 

·                       Debt principal repayments from time to timeas determined by the board of directors. The Trust’s current debt level is wellwithin the covenants specified in the debt agreements and, accordingly, thereare no current mandatory requirements for repayment. Refer to the “CapitalStructure and Liquidity” section of this MD&A for a detailed review of thedebt covenants.

 

·                       Income taxes that are not passed on tounitholders. The Trust has a liability for future income taxes due to theexcess of book value over the tax basis of the assets of the Trust and itscorporate subsidiaries. The Trust currently, and up until January 1, 2011,may minimize or eliminate cash income taxes in corporate subsidiaries bymaximizing deductions, however in future periods there may be cash income taxesif deductions are not sufficient to eliminate taxable income.  Taxability of the Trust is currently passedon to unitholders in the form of taxable distributions whereby corporate incometaxes are eliminated at the Trust level. The Trust taxation legislation, whichwill take effect in 2011, will result in taxes payable at the Trust level andtherefore distributions to unitholders will decrease.

 

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·                       Working capital requirements as determined bythe board of directors. Certain working capital amounts may be deducted fromcash flow from operating activities, however such amounts would be minimal andthe Trust does not anticipate any such deductions in the foreseeable future.

 

·                       The Trust has certain obligations for futurepayments relative to employee long-term incentive compensation. Presently, theTrust estimates that $19.2 million to $61.6 million will be paid out pursuantto such commitments in 2008 through 2010 subject to vesting provisions andfuture performance of the Trust. These amounts will reduce cash flow fromoperating activities and may in turn reduce distributions in future periods.

 

Cash flow from operating activities and distributions in total and perunit are summarized in Table 24:

 

**Table 24**

 
| **Cash flow from operating activities  and distributions** | ** ** | **2008**              | ** ** | **2007**   | ** ** | **% Change**          | ** ** | **2008**   | ** ** | **2007** | ** ** | **% Change** | ** ** |
|-------------------------------------------------------------------------------------|------------|-----------------------|------------|------------|------------|----------------------------|------------|------------|------------|----------|------------|-------------------|------------|
| ** **                                                                          | ** ** | **($ millions)** | ** ** | ** ** | ** ** | **($ per unit)** | ** ** | ** ** | ** ** |
| Cash flow from operating activities                                                 | ** ** | **944.4**             | ** ** | 704.9      |       | 34                         | ** ** | **4.37**   | ** ** | 3.35     |       | 30                |       |
| Net reclamation fund (contributions)  withdrawals (1)                               | ** ** | **(2.2**              | **)**      | 4.7        |       | (147                       | )          | **(0.01**  | **)**      | 0.02     |       | (150              | )          |
| Capital expenditures funded with cash flow  from operating activities               | ** ** | **(372.2**            | **)**      | (211.6     | )          | 76                         |       | **(1.72**  | **)**      | (1.01    | )          | 70                |       |
| Other (2)                                                                           | ** ** | **—**            | ** ** | —     |       | —                     |       | **0.03**   | ** ** | 0.04     |       | (25               | )          |
| Distributions                                                                       | ** ** | **570.0**             | ** ** | 498.0      |       | 14                         |       | **2.67**   | ** ** | 2.40     |       | 12                |       |

 

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(1)                      Includes interest income earned on thereclamation fund balances that is retained in the reclamation funds.

(2)                      Other represents the difference due todistributions paid being based on actual trust units outstanding at eachdistribution date whereas per unit cash flow from operating activities,reclamation fund contributions and capital expenditures funded with cash flowfrom operated activities are based on weighted average outstanding trust unitsin the year plus trust units issuable for exchangeable shares at year-end.

 

The Trust continuallyassesses distribution levels, in light of commodity prices and productionvolumes, to ensure that distributions are in line with the long-term strategyand objectives of the Trust as per the following guidelines:

 

·  Tomaintain a level of distributions that, in normal times, in the opinion ofManagement and the Board of Directors, is sustainable for a minimum period ofsix months after factoring in the impact of current commodity prices on cashflows.  The Trust’s objective is tonormalize the effect of volatility of commodity prices rather than to pass onthat volatility to unitholders in the form of fluctuating monthlydistributions.

 

·  Toensure that the Trust’s financial flexibility is maintained by a review of theTrust’s debt to equity and debt to cash flow from operating activitieslevels.  The use of cash flow fromoperating activities and proceeds from equity offerings to fund capitaldevelopment activities reduces the requirements of the Trust to use debt tofinance these expenditures. In 2008 the Trust funded 68 per cent of capitaldevelopment activities with a portion of cash flow from operating activities.Distributions and the actual amount of cash flows withheld to fund the Trust’scapital

 

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expenditureprogram is dependent on the commodity price environment and is subject to theapproval and discretion of the Board of Directors.

 

The actual amount of futuremonthly distributions is proposed by management and is subject to the approvaland discretion of the Board of Directors. The Board reviews futuredistributions in conjunction with their review of quarterly financial andoperating results.

 

Monthly distributions for the first quarter of 2009 have been set at$0.12 per unit subject to monthly review based on commodity price fluctuations.Revisions, if any, to the monthly distribution are normally announced on aquarterly basis in the context of prevailing and anticipated commodity pricesat that time.

 

**Historical Distributions by Calendar Year**

 

Table 25 presentsdistributions paid and payable for each calendar period.

 

**Table 25**

 
| **Calendar Year** | ** ** | **Distributions** | ** ** | **Taxable Portion** | ** ** | **Return of Capital** | ** ** |
|------------------------|------------|-------------------|------------|--------------------------|------------|---------------------------------|------------|
| 2009 YTD (2)           |       | 0.12              |       | 0.12                     |       | —                          |       |
| 2008                   |       | 2.67              |       | 2.62                     |       | 0.05                            |       |
| 2007                   |       | 2.40              |       | 2.32                     |       | 0.08                            |       |
| 2006(1)                |       | 2.60              |       | 2.55                     |       | 0.05                            |       |
| 2005                   |       | 1.94              |       | 1.90                     |       | 0.04                            |       |
| 2004                   |       | 1.80              |       | 1.69                     |       | 0.11                            |       |
| 2003                   |       | 1.78              |       | 1.51                     |       | 0.27                            |       |
| 2002                   |       | 1.58              |       | 1.07                     |       | 0.51                            |       |
| 2001                   |       | 2.41              |       | 1.64                     |       | 0.77                            |       |
| 2000                   |       | 1.86              |       | 0.84                     |       | 1.02                            |       |
| 1999                   |       | 1.25              |       | 0.26                     |       | 0.99                            |       |
| 1998                   |       | 1.20              |       | 0.12                     |       | 1.08                            |       |
| 1997                   |       | 1.40              |       | 0.31                     |       | 1.09                            |       |
| 1996                   |       | 0.81              |       | —                   |       | 0.81                            |       |
| **Cumulative**         | ** ** | **$**             | **23.82**  | ** **               | **$**      | **16.95**                       | ** ** | **$** | **6.87** | ** ** |
|                        |            |                   |            |                          |            |                                 |            |  |  |  |

 

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(1)                      Based on distributions paid and payable in2006.

(2)                      Based on distributions declared at January 31,2008 and estimated taxable portion of 2008 distributions of 98 per cent.

 

Please refer to the Trust’s website at www.arcenergytrust.com fordetails on 2008 monthly distributions and distribution dates for 2009.

 

**Taxation of Distributions**

 

Distributions comprise a return of capital portion (tax deferred) and areturn on capital portion (taxable). The return of capital component reducesthe cost basis of the trust units held. For 2008, distributions declared in thecalendar year will be 98 per cent return on capital or $2.62 per unit for theyear (taxable) and two per cent return of capital or $0.05 per unit for theyear (tax deferred). For a more detailed breakdown, please visit our website atwww.arcenergytrust.com.

 

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**Environmental Legislation Impacting the Trust**

 

On July 8, 2008 theAlberta government announced two new funds totaling $4 billion to reducegreenhouse gas emissions. The province will create a $2 billion fund to advancecarbon capture and storage projects while a second $2 billion fund will propelenergy-saving public transit in Alberta. The Trust is actively working to understand how the carbon capture fundswill be allocated as it may allow the Trust access to additional funding forits ongoing carbon capture and storage projects at Redwater and may increasethe possibility of achieving commercial viability of the CO2 injection program if proper infrastructure isput in place to capture and deliver CO2 to theRedwater area.

 

On February 19, 2008the British Columbia government introduced a consumer-based carbon tax.  Effective July 1, 2008, ARC is requiredto pay tax on all fuel used in the course of operations in that province.  Since July 1, 2008, the Trust paidapproximately $0.1 million of carbon tax to the BC Government.

 

**Contractual Obligations and Commitments**

 

The Trust has contractual obligations in the normal course ofoperations including purchase of assets and services, operating agreements,transportation commitments, sales commitments, royalty obligations, and leaserental obligations and employee agreements. These obligations are of arecurring and consistent nature and impact the Trust’s cash flows in an ongoingmanner. The Trust also has contractual obligations and commitments that are ofa less routine nature as disclosed in Table 26.

 

**Table 26**

 
| ** **                            | ** ** | **Payments Due by Period** | ** ** |
|---------------------------------------|------------|-------------------------------------------|------------|
| **($ millions)**                 | ** ** | **2009**                                  | ** ** | **2010-2011** | ** ** | **2012-2013** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
| Debt repayments (1)                   |       | 22.2                                      |       | 696.0 |   | 79.1 |   | 104.5 |   | 901.8 |   |
| Interest payments (2)                 |       | 12.8                                      |       | 22.2 |   | 15.4 |   | 10.0 |   | 60.4 |   |
| Reclamation fund contributions (3)    |       | 5.2                                       |       | 9.5 |   | 8.3 |   | 67.9 |   | 90.9 |   |
| Purchase commitments                  |       | 13.0                                      |       | 15.4 |   | 5.0 |   | 4.9 |   | 38.3 |   |
| Transportation commitments (4)        |       | —                                    |       | 14.9 |   | 21.9 |   | 21.0 |   | 57.8 |   |
| Operating leases                      |       | 7.0                                       |       | 9.8 |   | 14.3 |   | 81.8 |   | 112.9 |   |
| Risk management contract premiums (5) |       | 19.3                                      |       | — |   | — |   | — |   | 19.3 |   |
| Total contractual obligations         |       | 79.5                                      |       | 767.8 |   | 144.0 |   | 290.1 |   | 1,281.4 |   |

 

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(1)                      Long-term and short-term debt, excludinginterest.

(2)                      Fixed interest payments on senior securednotes.

(3)                      Contribution commitments to a restrictedreclamation fund associated with the Redwater property.

(4)                      Fixed payments for transporting productionfrom the Dawson gas plant, expected to be operational in early 2010.

(5)                       Fixedpremiums to be paid in future periods on certain commodity risk managementcontracts.

 

The above noted riskmanagement contract premiums are part of the Trust’s commitments related to itsrisk management program. In addition to the above premiums, the Trust hascommitments related to its risk management program. As the premiums are part ofthe underlying risk management contract, they have been recorded at fair marketvalue at December 31, 2008 on the balance sheet as part of risk managementcontracts.

 

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The Trust enters intocommitments for capital expenditures in advance of the expenditures being made.At a given point in time, it is estimated that the Trust has committed tocapital expenditures equal to approximately one quarter of its capital budgetby means of giving the necessary authorizations to incur the capital in afuture period. The Trust’s 2009 capital budget has been approved by the Boardat $450 million. This commitment has not been disclosed in the commitment table(Table 26) as it is of a routine nature and is part of normal course ofoperations for active oil and gas companies and trusts.

 

The 2009 capital budget of$450 million includes $11 million for leasehold development costs related tothe Trust’s new office space in downtown Calgary. These costs will be incurredthroughout 2009 with additional costs to be incurred in 2010.  The operating lease commitments for the newspace begin in the first quarter of 2010 and are included in Table 26.

 

The Trust is involved inlitigation and claims arising in the normal course of operations. Management isof the opinion that pending litigation will not have a material adverse impacton the Trust’s financial position or results of operations and therefore thecommitment table (Table 26) does not include any commitments for outstandinglitigation and claims.

 

The Trust has certain sales contracts with aggregators whereby theprice received by the Trust is dependent upon the contracts entered into by theaggregator. This commitment has not been disclosed in the commitment table(Table 26) as it is of a routine nature and is part of normal course ofoperations.

 

**Off Balance Sheet Arrangements**

 

The Trust has certain leaseagreements, all of which are reflected in the Contractual Obligations andCommitments table (Table 26), which were entered into in the normal course ofoperations. All leases have been treated as operating leases whereby the leasepayments are included in operating expenses or G&A expenses depending onthe nature of the lease. No asset or liability value has been assigned to theseleases in the balance sheet as of December 31, 2008.

 

**Fourth Quarter Financial and Operational Results**

 

Strong operational resultsin the fourth quarter resulted in $209.5 million of cash flow from operatingactivities despite volatile commodity prices and the global economic slow downduring the fourth quarter.  The Trustsuccessfully executed a $169.4 million capital development program thatcontributed to quarterly average production of 65,313 boe per day. The Trust’sdistributions were 61 per cent of cash flow from operating activities. Theremaining 39 per cent was used to fund $110.1 million of the fourth quartercapital development program and make contributions to the reclamation funds.The fourth quarter was an active one for the Trust with the drilling of 86gross wells on operated properties.  Intotal 52 natural gas wells and 33 oil wells were drilled with a 99 per centsuccess rate.

 

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·                  As a result of the sharp decline in commodityprices during the quarter, the Trust decreased monthly distributions to $0.15in an effort to preserve the Trust’s cash available to fund future capitalprograms. Total revenue decreased by $184.9 million in the fourth quarter of2008 as compared to the third quarter of 2008 despite recording slightly higherproduction in the fourth quarter. The weak commodity price environment hascontinued into 2009 and as a result, the Trust decreased monthly distributionsfurther to $0.12 per unit in order to provide flexibility for financing theTrust’s growth development in the Montney in 2009.

 

·                  The Trust’s fourth quarter production was65,313 boe per day in 2008, an increase of 1,324 boe per day from the fourthquarter of 2007 where production was 63,989. The increased production isattributable, in large part, to the development in the Dawson area innortheastern British Columbia.

 

·                  The Trust spent $197 million on capitalexpenditures and net acquisitions in the fourth quarter in 2008 compared to$144.3 million in 2007. The Trust had a very active fourth quarter with thedrilling of 86 gross wells (52 net wells) on operated properties with a 99 percent success rate. The Trust expanded its inventory of undeveloped land acreagewith the purchase of $38.8 million of land in the fourth quarter. The landacquired was in core areas where the Trust has identified strategic developmentopportunities.

 

·                  The fourth quarter netback before hedgingdecreased 18 per cent to $29.97 per boe in 2008 as compared to $36.63 for thesame period of 2007. The lower netback is largely attributed to the Trust’srealized oil price that decreased by 27 per cent in the fourth quarter of 2008when compared to the same period in 2007.

 

·                 Cash G&A expenses in the fourth quarterof 2008 increased to $2.93 per boe as compared to $1.96 for the same period in2007. The majority of the increase is attributable to a larger whole unit planpayment made in October of 2008 that included PTUs granted in 2005. The2007 October payment was only RTUs as no PTUs were issued in October of2004.

 

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**Table 27**

 
| **Fourth Quarter Financial and Operational Highlights**    | ** ** | ** **       | ** ** | ** **       | ** ** | ** **        | ** ** |
|-------------------------------------------------------------------------------------|------------|------------------|------------|------------------|------------|-------------------|------------|
| **(Cdn$ millions except per unit and per cent)** | ** ** | **Q4 2008** | ** ** | **Q4 2007** | ** ** | **% Change** | ** ** |
| Production (boe/d)                                                                  | ** ** | **65,313**       | ** ** | 63,989           |       | 2                 |       |
| Cash flow from operating activities                                                 | ** ** | **209.4**        | ** ** | 173.7            |       | 21                |       |
| Per unit                                                                            | ** ** | **$**            | **0.96**   | ** **       | $          | 0.82              |       | 17 |   |
| Distributions                                                                       | ** ** | **127.2**        | ** ** | 125.8            |       | 1                 |       |
| Per unit                                                                            | ** ** | **$**            | **0.58**   | ** **       | $          | 0.60              |       | (3 | ) |
| Per cent of cash flow from operating  activities                                    | ** ** | **61**           | ** ** | 72               |       | (15               | )          |
| Net income                                                                          | ** ** | **82.7**         | ** ** | 106.3            |       | (22               | )          |
| Per unit                                                                            | ** ** | **$**            | **0.38**   | ** **       | $          | 0.51              |       | (25 | ) |
| Prices                                                                              |       |             | ** ** |             |       |              |       |
| WTI (US$/bbl)                                                                       | ** ** | **58.75**        | ** ** | 90.63            |       | (35               | )          |
| Cdn$/US$ exchange rate                                                         | ** ** | **1.21**         | ** ** | 1.02             |       | 19                |       |
| Realized oil price (Cdn $/bbl)                                                      | ** ** | **56.26**        | ** ** | 77.53            |       | (27               | )          |
| AECO gas monthly index (Cdn $/mcf)                                                  | ** ** | **6.79**         | ** ** | 6.00             |       | 13                |       |
| Realized gas price (Cdn $/mcf)                                                      | ** ** | **7.48**         | ** ** | 6.32             |       | 18                |       |
| Operating netback ($/boe)                                                           |       |             | ** ** |             |       |              |       |
| Revenue, before hedging                                                             | ** ** | **50.06**        | ** ** | 57.42            |       | (13               | )          |
| Royalties                                                                           | ** ** | **(9.14**        | **)**      | (10.46           | )          | (13               | )          |
| Transportation                                                                      | ** ** | **(0.86**        | **)**      | (0.69            | )          | 25                |       |
| Operating costs                                                                     | ** ** | **(10.09**       | **)**      | (9.64            | )          | 5                 |       |
| Netback (before hedging)                                                            | ** ** | **29.97**        | ** ** | 36.63            |       | (18               | )          |
| Cash hedging gain (loss)                                                            | ** ** | **2.38**         | ** ** | (0.20            | )          | 1,290             |       |
| Netback (after hedging)                                                             | ** ** | **$**            | **32.35**  | ** **       | $          | 36.43             |       | (11 | ) |
| Capital expenditures                                                                | ** ** | **169.4**        | ** ** | 139.3            |       | 22                |       |
| Capital funded with cash flow from operating  activities (per cent)                 | ** ** | **65**           | ** ** | 32               |       | 103               |       |

 

**Critical Accounting Estimates**

 

The Trust has continuously evolved and documented its management andinternal reporting systems to provide assurance that accurate, timely internaland external information is gathered and disseminated.

 

The Trust’s financial and operating results incorporate certainestimates including:

 

·                  estimated revenues, royalties and operatingcosts on production as at a specific reporting date but for which actualrevenues and costs have not yet been received;

·                  estimated capital expenditures on projectsthat are in progress;

·                  estimated depletion, depreciation andaccretion that are based on estimates of oil and gas reserves that the Trustexpects to recover in the future;

·                  estimated fair values of derivative contractsthat are subject to fluctuation depending upon the underlying commodity pricesand foreign exchange rates;

·                  estimated value of asset retirementobligations that are dependent upon estimates of future costs and timing ofexpenditures; and

·                  estimated future recoverable value ofproperty, plant and equipment and goodwill.

 

The Trust has hired individuals and consultants who have the skillsrequired to make such estimates and ensures that individuals or departmentswith the most knowledge of the activity are responsible for the estimates.Further, past estimates are reviewed and compared to actual results, and actualresults are compared to budgets in order to make more informed decisions onfuture estimates.

 

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The ARC leadership team’s mandate includes ongoing development ofprocedures, standards and systems to allow ARC staff to make the best decisionspossible and ensuring those decisions are in compliance with the Trust’senvironmental, health and safety policies.

 

**Assessment of Business Risks**

 

The ARC management team is focused on long-term strategic planning andhas identified the key risks, uncertainties and opportunities associated withthe Trust’s business that can impact the financial results as follows:

 

VOLATILITY OF OIL ANDNATURAL GAS PRICES

 

The Trust’s operational results and financial condition, and thereforethe amount of distributions paid to the unitholders and the amount of capitalexpenditures will be dependent on the prices received for oil and natural gasproduction.  Oil and natural gas priceshave recently declined precipitously and monthly distributions that reached ahigh point of $0.28 per unit in August of 2008 declined to $0.15 per unitat December 31, 2008.  Currentdistributions are $0.12 per unit and continued low oil and natural gas pricesor further declines in oil and natural gas prices will result in furtherdeclines in, or elimination of, such distributions. Oil and natural gas pricesare determined by economic and in some circumstances political factors. Supplyand demand factors, including weather and general economic conditions as wellas conditions in other oil and natural gas regions impact prices. Any movementin oil and natural gas prices will also have an effect on the Trust’s financialcondition and the Trust’s ability to continue with its capital expenditureprogram.  ARC may manage the riskassociated with changes in commodity prices by entering into oil or natural gasprice derivative contracts. If ARC engages in activities to manage itscommodity price exposure, the Trust may forego the benefits it would otherwiseexperience if commodity prices were to increase. In addition, commodityderivative contracts activities could expose ARC to losses. To the extent thatARC engages in risk management activities related to commodity prices, it willbe subject to credit risks associated with counterparties with which itcontracts.

 

CAPITAL MARKETS

 

As a result of the weakenedglobal economic situation, the Trust along with all other oil and gas entitieswill have restricted access to capital and increased borrowing costs. Althoughthe Trust’s business and asset base have not changed, the lending capacity ofall financial institutions has diminished and risk premiums have increased. Asfuture capital expenditures will be financed out of cash generated fromoperations, borrowings and possible future equity sales, the Trust’s ability todo so is dependent on, among other factors, the overall state of capitalmarkets and investor appetite for investments in the energy industry and theTrust’s securities in particular. To the extent that external sources ofcapital become limited or unavailable or available on onerous terms, the Trust’sability to make capital investments and maintain existing assets may beimpaired, and its assets, liabilities, business, financial condition, resultsof operations and distributions may be materially and adversely affected as aresult.

 

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Based on current fundsavailable and expected cash from operations, the Trust believes it hassufficient funds available to fund its projected capital expenditures in 2009.However, if cash flow from operations is lower than expected or capital costsfor these projects exceed current estimates, or if the Trust incurs majorunanticipated expenses related to development or maintenance of its existingproperties, it may be required to seek additional capital to maintain itscapital expenditures at planned levels. Failure to obtain any financingnecessary for the Trust’s capital expenditure plans may result in a delay indevelopment of production on the Trust’s properties or a decrease indistributions.

 

REFINANCING AND DEBT SERVICE

 

The Trust currently has an$800 million syndicated credit facility with eleven banks.  In normal circumstances, borrowers such asARC rely on the fact that the banks will honor their contractual commitments tofund draws as required.  In today’seconomic environment there is a risk that one or more of the banks included inthe Trust’s syndicate may not honor draws requested by the Trust.   At the option of the Trust, the lenders willreview the credit facility each year and determine if they will extend foranother year. In the event that the facility is not extended before April 11,2011, indebtedness under the facility will become repayable at that date. Thereis also a risk that the credit facility will not be renewed for the same amountor on the same terms. Any of these events could affect the Trust’s ability tofund ongoing operations. The Trust currently has US$212 million of U.S.denominated long-term debt outstanding which requires principal repaymentsstarting in April 2009 and continuing until December 2017. The Trustintends to fund these debt maturities with existing credit facilities. In theevent the Trust is unable to refinance its debt obligations it may impact theTrust’s ability to fund its ongoing operations and distribute cash.

 

The Trust is required to comply with covenants under the creditfacility. In the event that the Trust does not comply with covenants under thecredit facility, the Trust’s access to capital could be restricted or repaymentcould be required. The Trust routinely reviews the covenants based on actualand forecast results and has the ability to make changes to its developmentplans and/or distribution policy to comply with covenants under the creditfacility. The lenders have security interests over substantially all of theassets of ARC. If ARC becomes unable to pay its debt service charges orotherwise commits an event of default such as bankruptcy, the lender mayforeclose onsuch assets of ARC or sell the working interests.

 

At December 31, 2008,the Trust had approximately $160 million of unused credit available under itsbank credit facility as well as the ability to issue an additional US$113million of long-term notes under an agreement with one lender. This option,which will expire in May 2009 unless it is renewed, would allow the Trustto issue long-term notes at a rate equal to the related U.S. treasuriescorresponding to the term of notes plus an appropriate credit spread adjustmentat the time of issuance.

 

Amounts paid in respect of interest and principal on debt may reducedistributions to unitholders. Variations in interest rates and scheduledprincipal repayments could result in significant changes in the amount requiredto be applied to debt service before payment of distributions to unitholders.Certain covenants of the agreements with ARC’s lenders may also limitdistributions to unitholders. Although ARC believes the credit facilities willbe sufficient for the Trust’s

 

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immediate requirements, there can be no assurance that the amount willbe adequate for the future financial obligations of the Trust or thatadditional funds will be able to be obtained.

 

COUNTERPARTY RISK

 

ARC assumes customer credit risk associated with oil and gas sales,financial hedging transactions and joint venture participants.  In the event that the Trust’s counterpartiesdefault on payments to the Trust, the cash flows of the Trust will be impactedand distributions paid to unitholders may be impacted.  The Trust has established credit policies andcontrols designed to mitigate the risk of default or non-payment with respectto oil and gas sales, financial hedging transactions and joint ventureparticipants. A diversified sales customer base is maintained and exposure toindividual entities is reviewed on a regular basis.

 

VARIATIONS IN INTEREST RATESAND FOREIGN EXCHANGE RATES

 

Variations in interest rates could result in an increase in the amountthe Trust pays to service debt, resulting in a decrease in distributions tounitholders. World oil prices are quoted in U.S. dollars and the price receivedby Canadian producers is therefore affected by the Canadian/U.S. dollarexchange rate that may fluctuate over time. A material increase in the value ofthe Canadian dollar may negatively impact the Trust’s net production revenue.Over the last two years, the Canadian dollar has experienced significantvolatility, impacting the amount of Canadian dollars received by the Trust forits production. Continued volatility in the Canadian dollar may affect futuredistributions. ARC may initiate certain derivative contracts to attempt tomitigate these risks. To the extent that ARC engages in risk managementactivities related to foreign exchange rates, it will be subject to credit riskassociated with counterparties with which it contracts. The increase in theexchange rate for the Canadian dollar and future Canadian/U.S. exchange ratesmay impact future distributions to the unitholders and the future value of theTrust’s reserves as determined by independent evaluators.

 

RESERVES ESTIMATES

 

The reserves and recovery information contained in ARC’s independentreserves evaluation is only an estimate. The actual production and ultimatereserves from the properties may be greater or less than the estimates preparedby the independent reserves evaluator. The reserves report was prepared usingcertain commodity price assumptions. If lower prices for crude oil, natural gasliquids and natural gas are realized by the Trust and substituted for the priceassumptions utilized in those reserves reports, the present value of estimatedfuture net cash flows for the Trust’s reserves as well as the amount of theTrust’s reserves would be reduced and the reduction could be significant,particularly based on the constant price case assumptions.

 

DEPLETION OF RESERVES ANDMAINTENANCE OF DISTRIBUTION

 

ARC’s future oil and natural gas reserves and production, and thereforeits cash flows, will be highly dependent on ARC’s success in exploiting itsreserves base and acquiring additional reserves. Without reserves additionsthrough acquisition or development activities, the Trust’s reserves andproduction will decline over time as the oil and natural gas reserves areproduced out.

 

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There can be no assurance that the Trust will make sufficient capitalexpenditures to maintain production at current levels; nor as a consequence,that the amount of distributions by the Trust to unitholders can be maintainedat current levels.

 

There can be no assurance that ARC will be successful in developing oracquiring additional reserves on terms that meet the Trust’s investmentobjectives.

 

CHANGES IN INCOME TAXLEGISLATION

 

Income tax laws, or other laws, or provincial royalty programs relatingto the oil and gas industry may in the future be changed or interpreted in amanner that adversely affects the Trust or its unitholders.  Tax authorities having jurisdiction over theTrust or unitholders may disagree with how the Trust calculates its income fortax purposes or how we calculate payment of crown royalties or could changeadministrative practices to the detriment of the Trust and its unitholders.

 

On October 31, 2006,the Finance Minister announced the federal government’s plan regarding the taxationof Income Trusts. Currently, distributions paid to unitholders, other thanreturns of capital, are claimed as a deduction by the Trust in arriving attaxable income whereby tax is eliminated at the Trust level and is paid by theunitholders. The Trust tax legislation which received Royal Assent on June 22,2007, will result in a two-tiered tax structure whereby distributions wouldfirst be subject to the federal corporate income tax rate plus a deemedProvincial income tax at the Trust level commencing in 2011 (or earlier, iftrusts that were publicly traded as of October 31, 2006 exceed the normalgrowth guidelines announced by the Minister on December 15, 2006).  On February 26, 2008 the Minister ofFinance announced as part of the federal budget that the provincial componentof the tax on the Trust is to be calculated based on the general provincialrate in each province in which the Trust has a permanent establishment.  This is the same way a corporation wouldcalculate its provincial tax rate, however it is different than the Provincialtax component included in the SIFT Rules, which currently provide for a deemedrate of 13 per cent.  At December 31,2008 the Trust has used the deemed 13 per cent provincial rate to calculate itsfuture income taxes as the proposed legislation had not been issued forcalculating the provincial rate.  On February 1,2009 the Minister of Finance tabled a Notice of Ways and Means that includesthe proposed legislation for calculating the provincial tax rate.

 

Management and the Board ofDirectors continue to review the impact of this tax on our business strategyand while there has not been a decision as to ARC’s future direction at thistime we are of the opinion that the conversion from a trust to a corporationmay be the most logical and tax efficient alternative for ARC unitholders. Weexpect future technical interpretations and details will further clarify thelegislation. Canadian investors who hold their units in a taxable account willbe relatively indifferent on an after tax basis as to whether ARC is structuredas a corporation or as a Trust in 2011.  However, Canadian tax deferredinvestors (those holding their Trust Units in a tax deferred vehicle such as anRRSP, RRIF or pension plan) and foreign investors will realize a lower returnon distributions in 2011 due to the introduction of the SIFT Tax should ARCstay as a Trust and their inability to claim the dividend tax credit if ARCconverts to a corporation.

 

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NEW ROYALTY FRAMEWORK

 

The Alberta Government’s “New Royalty Framework’ (“NRF”) took effect onJanuary 1, 2009.  The new frameworkwill impact the Alberta Crown Royalties on all of the Trust’s oil and naturalgas production in Alberta.  As royaltiesunder the new Framework are sensitive to both commodity prices and productionlevels, the estimated NRF Alberta and corporate royalty rates will fluctuatewith commodity prices, well production rates, production decline of existingwells, and performance and location of new wells drilled.  The fluctuations in royalty rates will impactthe cash flows of the Trust and may impact the amount of distributions paid tounitholders.    A detailed analysis ofthe potential impact of the NRF is included in Tables 15 and 16 of theMD&A.

 

ACQUISITIONS

 

The price paid for acquisitions is based on engineering and economicestimates of the potential reserves made by independent engineers modified toreflect the technical views of management. These assessments include a numberof material assumptions regarding such factors as recoverability andmarketability of oil, natural gas, natural gas liquids and sulphur, futureprices of oil, natural gas, natural gas liquids and sulphur and operatingcosts, future capital expenditures and royalties and other government leviesthat will be imposed over the producing life of the reserves. Many of thesefactors are subject to change and are beyond the control of the operators ofthe working interests, management and the Trust. In particular, changes in theprices of and markets for oil, natural gas, natural gas liquids and sulphurfrom those anticipated at the time of making such assessments will affect theamount of future distributions and as such the value of the units. In addition,all such estimates involve a measure of geological and engineering uncertaintythat could result in lower production and reserves than attributed to theworking interests. Actual reserves could vary materially from these estimates.Consequently, the reserves acquired may be less than expected, which couldadversely impact cash flows and distributions to unitholders.

 

ENVIRONMENTAL CONCERNS ANDIMPACT ON ENHANCED OIL RECOVERY PROJECTS

 

The oil and natural gasindustry is subject to environmental regulation pursuant to local, provincialand federal legislation. A breach of such legislation may result in theimposition of fines or issuance of clean up orders in respect of ARC or itsworking interests. Such legislation may be changed to impose higher standardsand potentially more costly obligations on ARC.   Furthermore, management believes the federalpolitical parties, appear to favor new programs for environmental laws andregulation, particularly in relation to the reduction of emissions, and thereis no assurance that any such programs, laws or regulations, if proposed andenacted, will not contain emission reduction targets which ARC cannot meet, andfinancial penalties or charges could be incurred as a result of the failure tomeet such targets.  In particular thereis uncertainty regarding the Federal Government’s Regulatory Framework for AirEmissions (“Framework”), as issued under the Canadian Environmental ProtectionAct.

 

Additionally, the potential impact on the Trust’s operations andbusiness of the Framework, with respect to instituting reductions of greenhousegases, is not possible to quantify at this time as specific measures formeeting Canada’s commitments have not been developed. Currently, companies arepermitted to emit CO2 intothe atmosphere with no requirement to capture and re-inject the emissions. Inorder for the Trust to carry out its enhanced oil recovery program it isnecessary to obtain CO2 at acost effective rate. Given that companies are not forced to capture their

 

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emissions, the infrastructure has not been put in place to facilitatethis process. Without any additional provisions from the government, theeconomic parameters of the Trust’s enhanced oil recovery programs would be limited.

 

Although ARC has establisheda reclamation fund for the purpose of funding its future environmental andreclamation obligations based on current estimates, there can be no assurancethat the Trust will be able to satisfy its actual future environmental andreclamation obligations with the balance of the fund and therefore future cashflows may be required to fund future reclamation spending which may reduce theamount of distributions paid to unitholders.

 

OPERATIONAL MATTERS

 

The operation of oil and gas wells involves a number of operating andnatural hazards that may result in blowouts, environmental damage and otherunexpected or dangerous conditions resulting in damage to operatingsubsidiaries of the Trust and possible liability to third parties. ARCmaintains liability insurance, where available, in amounts consistent withindustry standards. Business interruption insurance may also be purchased forselected facilities, to the extent that such insurance is available. ARC maybecome liable for damages arising from such events against which it cannotinsure or against which it may elect not to insure because of high premiumcosts or other reasons. Costs incurred to repair such damage or pay suchliabilities will reduce distributable cash.

 

Continuing production from a property, and to some extent the marketingof production there from, are largely dependent upon the ability of theoperator of the property. Approximately 24 per cent of ARC’s production isoperated by third parties. ARC has limited ability to influence costs onpartner operated properties. Operating costs on most properties have increasedsteadily over recent years. To the extent the operator fails to perform thesefunctions properly, ARC’s revenue from such property may be reduced. Paymentsfrom production generally flow through the operator and there is a risk ofnon-payment delay and additional expense in receiving such revenues if theoperator becomes insolvent. Although satisfactory title reviews are generallyconducted in accordance with industry standards, such reviews do not guaranteeor certify that a defect in the chain of title may not arise to defeat theclaim of the Trust to certain properties. A reduction of the distributionscould result in such circumstances.

 

**Disclosure Controls and Procedures**

 

As of December 31, 2008, an internal evaluation was carried out ofthe effectiveness of the Trust’s disclosure controls and procedures as definedin Rule 13a-15 under the US Securities Exchange Act of 1934 and as definedin Canada by National Instrument 52-109, Certification of Disclosure in Issuers’Annual and Interim Filings. Based on that evaluation, the President and ChiefExecutive Officer and the Senior Vice President Finance and Chief FinancialOfficer concluded that the disclosure controls and procedures are effective toensure that the information required to be disclosed in the reports that theTrust files or submits under the Exchange Act or under Canadian Securitieslegislation is recorded, processed, summarized and reported, within the timeperiods specified in the rules and forms therein. Disclosure controls andprocedures include, without limitation, controls and procedures designed toensure that the information required to be disclosed by the Trust in thereports that it files or submits under the Exchange Act or under CanadianSecurities Legislation is accumulated and communicated to the Trust’smanagement, including the senior executive and financial officers, asappropriate to allow timely decisions regarding the required disclosure.

 

35

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**Internal Control over Financial Reporting**

 

Internal control over financial reporting is a process designed toprovide reasonable assurance that all assets are safeguarded, transactions areappropriately authorized and to facilitate the preparation of relevant,reliable and timely information.  Becauseof its inherent limitations, internal control over financial reporting may notprevent or detect misstatements. Management has assessed the effectiveness of the Trust’s internalcontrol over financial reporting as defined in Rule 13a-15 under the USSecurities Exchange Act of 1934 and as defined in Canada by National Instrument52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Theassessment was based on the framework in *InternalControl — Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission. Management concluded that the Trust’sinternal control over financial reporting was effective as of December 31,2008. The effectiveness of the Trust’s internal control over financialreporting as of December 31, 2008 has been audited by Deloitte &Touche LLP, as reflected in their report for 2008.  No changes were made to the Trust’s internalcontrol over financial reporting during the year ending December 31, 2008,that have materially affected, or are reasonably likely to materially affect,the internal controls over financial reporting.

 

**Financial Reporting Update**

 

Current Year AccountingChanges 

 

Effective January 1,2008, the Trust adopted three new accounting standards that were issued by theCanadian Institute of Chartered Accountants (“CICA”): Handbook Section 1535,Capital Disclosures, Section 3862, Financial Instruments — Disclosures andSection 3863, Financial Instruments — Presentation.

 

*A.  Capital Disclosures*

 

Section 1535establishes standards for disclosing information regarding an entity’s capitaland how it is managed.

 

*B.  Financial Instruments — Disclosures, FinancialInstruments — Presentation*

 

Sections 3862 and 3863establish standards for enhancing financial statements users’ understanding ofthe significance of financial instruments to an entity’s financial position,performance and cash flows.  They requirethat entities provide disclosures regarding the nature and extent of risksarising from financial instruments to which they are exposed both during thereporting period and at the balance sheet date, as well as how the entitiesmanage those risks.

 

These standards were adoptedprospectively.

 

Future Accounting Changes

 

*A.  Goodwill and Intangible Assets*

 

In February 2008, theCICA issued Section 3064, Goodwill and Intangible Assets, replacing Section 3062,Goodwill and Other Intangible Assets and Section 3450, Research andDevelopment Costs.  The new Section willbe effective

 

36

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on January 1,2009.  Section 3064 establishesstandards for the recognition, measurement, presentation and disclosure ofgoodwill and intangible assets subsequent to its initial recognition.  Standards concerning goodwill are unchangedfrom the standards included in the previous Section 3062.  The Trust is currently evaluating the impactof the adoption of this new Section, however does not expect a material impacton its Consolidated Financial Statements.

 

*B.  International Financial Reporting Standards (“IFRS”)*

 

In April 2008, the CICApublished the exposure draft “Adopting IFRSs in Canada”. The exposure draftproposes to incorporate IFRSs into the CICA Accounting Handbook effective forinterim and annual financial statements relating to fiscal years beginning onor after January 1, 2011. At this date, publicly accountable enterpriseswill be required to prepare financial statements in accordance with IFRSs. TheTrust is currently reviewing the standards to determine the potential impact onits Consolidated Financial Statements.   At this time, the Trust has appointed internal staff along with sponsorshipfrom the senior leadership team to review the impact of converting to IFRS onthe accounting policies, information and computer systems, internal anddisclosure controls, financial reporting in addition to the changes in theTrust’s financial statements.  Inaddition, an external advisor has been retained to assist the Trust in theconversion project.

 

**Non-GAAP Measures**

 

Historically, management used the non-GAAP measure Cash Flow or cashflow from operations to analyze operating performance, leverage and liquidity.We have now chosen to utilize the GAAP measure cash flow from operatingactivities instead of Cash Flow. There are two differences between the twomeasures and cash flow from operating activities; positive or negative changesin non-cash working capital and the deduction of expenditures on siterestoration and reclamation as they appear on the Consolidated Statements ofCash Flows. Although management feels that Cash Flow is a valued measure offunds generated by the Trust during the reported quarter, we have changed ourdisclosure to only discuss the GAAP measure in the MD&A in order to avoidany potential confusion by readers of our financial information and in ouropinion, to more fully comply with the intent of certain regulatoryrequirements.

 

Our historical measure of Cash Flow reflected revenues and costs forall months reported in the period. This amount, however, comprised accruals forat least one month of revenue and approximately two months of costs. The oiland gas industry customarily operates in such a way that revenues are typicallycollected on the 25th day ofthe month following the actual production month. Royalties are typically paidtwo months following the actual production month and operating costs are paidas the invoices are received. This can take several months; however, mostinvoices for operated properties are paid within approximately two months ofthe production month.  In the event thatcommodity prices and or volumes have changed significantly from the last monthof the previous reporting period over the last month of the current reportingperiod, a difference could occur between cash flow from operating activitiesand our historical non-GAAP measure of Cash Flow or cash flow from operations.Additionally, periods where the Trust spends a significant amount on siterestoration and reclamation would result in a difference between cash flow fromoperating activities and Cash Flow.

 

37

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At the time of writing thisMD&A, substantially all revenues have been collected for the productionperiod of December 2008. Management performs analysis on the amountscollected to ensure that the amounts accrued for December are accurate.Analysis is also performed regularly on royalties and operating costs to ensurethat amounts have been accurately accrued.

 

Management uses certain keyperformance indicators (“KPIs”) and industry benchmarks such as distributionsto unitholders as a per cent of cash flow from operating activities, operatingnetbacks (“netbacks”), total capitalization, finding, development andacquisition costs, recycle ratio, reserve life index, reserves per unit andproduction per unit, net asset value and total returns to analyze financial andoperating performance. Management feels that these KPIs and benchmarks are keymeasures of profitability and overall sustainability for the Trust. These KPIsand benchmarks as presented do not have any standardized meaning prescribed byCanadian GAAP and therefore may not be comparable with the calculation ofsimilar measures for other entities.

 

**Forward-lookingInformation and Statements**

 

Thisnews release contains certain forward-looking information and statements withinthe meaning of applicable securities laws. The use of any of the words “expect”,“anticipate”, “continue”, “estimate”, “objective”, “ongoing”, “may”, “will”, “project”,“should”, “believe”, “plans”, “intends”, “strategy” and similar expressions areintended to identify forward-looking information or statements. In particular,but without limiting the foregoing, this news release contains forward-lookinginformation and statements pertaining to the following: the volumes andestimated value of ARC’s oil and gas reserves; the life of ARC’s reserves; thevolume and product mix of ARC’s oil and gas production; future oil and naturalgas prices and ARC’s commodity risk management programs; the amount of futureasset retirement obligations; future liquidity and financial capacity; future resultsfrom operations and operating metrics; future costs, expenses and royaltyrates; future interest costs; future development, exploration, acquisition anddevelopment activities (including drilling plans) and related capitalexpenditures, future tax treatment of income trusts and future taxes payable byARC; and ARC’s tax pools.

 

Theforward-looking information and statements contained in this news releasereflect several material factors and expectations and assumptions of ARCincluding, without limitation: that ARC will continue to conduct its operationsin a manner consistent with past operations; the general continuance of currentindustry conditions; the continuance of existing (and in certain circumstances,the implementation of proposed) tax, royalty and regulatory regimes; theaccuracy of the estimates of ARC’s reserve and resource volumes; certaincommodity price and other cost assumptions; and the continued availability ofadequate debt and equity financing and cash flow to fund its plans expenditures;ARC believes the material factors, expectations and assumptions reflected inthe forward-looking information and statements are reasonable but no assurancecan be given that these factors, expectations and assumptions will prove to becorrect.

 

Theforward-looking information and statements included in this news release arenot guarantees of future performance and should not be unduly relied upon. Suchinformation and statements involve known and unknown risks, uncertainties andother factors that may cause actual results or events to differ materially fromthose anticipated 

 

38

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insuch forward-looking information or statements including, without limitation:changes in commodity prices; changes in the demand for or supply of ARC’sproducts; unanticipated operating results or production declines; changes intax or environmental laws, royalty rates or other regulatory matters; changesin development plans of ARC or by third party operators of ARC’s properties,increased debt levels or debt service requirements; inaccurate estimation ofARC’s oil and gas reserve and resource volumes; limited, unfavorable or a lackof access to capital markets; increased costs; a lack of adequate insurancecoverage; the impact of competitors; and certain other risks detailed from timeto time in ARC’s public disclosure documents (including, without limitation,those risks identified in this news release and in ARC’s Annual InformationForm).

 

The forward-looking informationand statements contained in this news release speak only as of the date of thisnews release, and none of ARC or its subsidiaries assumes any obligation topublicly update or revise them to reflect new events or circumstances, exceptas may be required pursuant to applicable laws.

 

**AdditionalInformation**

 

Additional information relatingto ARC can be found on SEDAR at www.sedar.com.

 

39

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**ANNUALHISTORICAL REVIEW**

 
| **For the year ended December 31****(Cdn $ millions, except per unit amounts)** | ** ** | **2008**    | ** ** | **2007** | ** ** | **2006**    | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------------------------------------------------------------------------------------------------|------------|-------------|------------|----------|------------|-------------|------------|----------|------------|----------|------------|
| **FINANCIAL**                                                                                                                          |       |        |       |     |       |        |       |     |       |     |       |
| Revenue before royalties                                                                                                               | ** ** | **1,706.4** |       | 1,251.6  | ** ** | **1,230.5** |       | 1,165.2  |       | 901.8    |       |
| Per unit (1)                                                                                                                           | ** ** | **7.90**    |       | 5.95     | ** ** | **6.02**    |       | 6.10     |       | 4.85     |       |
| Cash flow from operating activities (2)                                                                                                | ** ** | **944.4**   |       | 704.9    | ** ** | **734.0**   |       | 616.7    |       | 446.4    |       |
| Per unit – basic(1)                                                                                                               | ** ** | **4.37**    |       | 3.35     | ** ** | **3.59**    |       | 3.23     |       | 2.40     |       |
| Per unit – diluted                                                                                                                | ** ** | **4.37**    |       | 3.35     | ** ** | **3.58**    |       | 3.20     |       | 2.38     |       |
| Net income                                                                                                                             | ** ** | **533.0**   |       | 495.3    | ** ** | **460.1**   |       | 356.9    |       | 241.7    |       |
| Per unit – basic (3)                                                                                                              | ** ** | **2.50**    |       | 2.39     | ** ** | **2.28**    |       | 1.90     |       | 1.32     |       |
| Per unit – diluted                                                                                                                | ** ** | **2.50**    |       | 2.39     | ** ** | **2.27**    |       | 1.88     |       | 1.31     |       |
| Distributions                                                                                                                          | ** ** | **570.0**   |       | 498.0    | ** ** | **484.2**   |       | 376.6    |       | 330.0    |       |
| Per unit (4)                                                                                                                           | ** ** | **2.67**    |       | 2.40     | ** ** | **2.40**    |       | 1.99     |       | 1.80     |       |
| Total assets                                                                                                                           | ** ** | **3,766.7** |       | 3,533.0  | ** ** | **3,479.0** |       | 3,251.2  |       | 2,305.0  |       |
| Total liabilities                                                                                                                      | ** ** | **1,624.6** |       | 1,491.3  | ** ** | **1,550.6** |       | 1,415.5  |       | 755.7    |       |
| Net debt outstanding (5)                                                                                                               | ** ** | **961.9**   |       | 752.7    | ** ** | **739.1**   |       | 578.1    |       | 264.8    |       |
| Weighted average trust units (millions) (6)                                                                                            | ** ** | **216.0**   |       | 210.2    | ** ** | **204.4**   |       | 191.2    |       | 186.1    |       |
| Trust units outstanding and issuable at  period end (millions)(6)                                                                      | ** ** | **219.2**   |       | 213.2    | ** ** | **207.2**   |       | 202.0    |       | 188.8    |       |
| **CAPITAL  EXPENDITURES**                                                                                                              |       |        |       |     |       |        |       |     |       |     |       |
| Geological and geophysical                                                                                                             | ** ** | **27.1**    |       | 14.9     | ** ** | **11.4**    |       | 9.2      |       | 5.4      |       |
| Land                                                                                                                                   | ** ** | **122.4**   |       | 77.5     | ** ** | **32.4**    |       | 9.1      |       | 4.1      |       |
| Drilling and completions                                                                                                               | ** ** | **305.4**   |       | 229.5    | ** ** | **240.5**   |       | 191.8    |       | 140.4    |       |
| Plant and facilities                                                                                                                   | ** ** | **90.4**    |       | 72.1     | ** ** | **77.6**    |       | 55.0     |       | 41.1     |       |
| Other capital                                                                                                                          | ** ** | **3.3**     |       | 3.2      | ** ** | **2.6**     |       | 3.7      |       | 2.8      |       |
| Total capital expenditures                                                                                                             | ** ** | **548.6**   |       | 397.2    | ** ** | **364.5**   |       | 268.8    |       | 193.8    |       |
| Property acquisitions (dispositions), net                                                                                              | ** ** | **51.0**    |       | 42.5     | ** ** | **115.2**   |       | 91.3     |       | (58.2    | )          |
| Corporate acquisitions (7)                                                                                                             | ** ** | **—**  |       | —   | ** ** | **16.6**    |       | 505.0    |       | 72.0     |       |
| Total capital expenditures and net  acquisitions                                                                                       | ** ** | **599.6**   |       | 439.7    | ** ** | **496.3**   |       | 865.1    |       | 207.6    |       |
| **OPERATING**                                                                                                                          |       |        |       |     |       |        |       |     |       |     |       |
| Production                                                                                                                             |       |        |       |     |       |        |       |     |       |     |       |
| Crude oil (bbl/d)                                                                                                                      | ** ** | **28,513**  |       | 28,682   | ** ** | **29,042**  |       | 23,282   |       | 22,961   |       |
| Natural gas (mmcf/d)                                                                                                                   | ** ** | **196.5**   |       | 180.1    | ** ** | **179.1**   |       | 173.8    |       | 178.3    |       |
| Natural gas liquids (bbl/d)                                                                                                            | ** ** | **3,861**   |       | 4,027    | ** ** | **4,170**   |       | 4,005    |       | 4,191    |       |
| Total (boe per day 6:1)                                                                                                                | ** ** | **65,126**  |       | 62,723   | ** ** | **63,056**  |       | 56,254   |       | 56,870   |       |
| Average prices                                                                                                                         |       |        |       |     |       |        |       |     |       |     |       |
| Crude oil ($/bbl)                                                                                                                      | ** ** | **94.20**   |       | 69.24    | ** ** | **65.26**   |       | 61.11    |       | 47.03    |       |
| Natural gas ($/mcf)                                                                                                                    | ** ** | **8.58**    |       | 6.75     | ** ** | **6.97**    |       | 8.96     |       | 6.78     |       |
| Natural gas liquids ($/bbl)                                                                                                            | ** ** | **69.71**   |       | 54.79    | ** ** | **52.63**   |       | 49.92    |       | 39.04    |       |
| Oil equivalent ($/boe)                                                                                                                 | ** ** | **71.25**   |       | 54.54    | ** ** | **53.33**   |       | 56.54    |       | 43.13    |       |
| **RESERVES**                                                                                                                           |       |        |       |     |       |        |       |     |       |     |       |
| (company  interest)(8)                                                                                                                 |       |        |       |     |       |        |       |     |       |     |       |
| Proved plus probable reserves                                                                                                          |       |        |       |     |       |        |       |     |       |     |       |
| Crude oil and NGL (mbbl)                                                                                                               | ** ** | **153,020** |       | 158,341  | ** ** | **162,193** |       | 163,385  |       | 123,226  |       |
| Natural gas (bcf)                                                                                                                      | ** ** | **1,012.2** |       | 768.2    | ** ** | **743.6**   |       | 741.7    |       | 724.5    |       |
| Total (mboe)                                                                                                                           | ** ** | **321,723** |       | 286,370  | ** ** | **286,125** |       | 286,997  |       | 243,974  |       |
| **TRUST UNIT TRADING**                                                                                                                 |       |        |       |     |       |        |       |     |       |     |       |
| (based  on intra-day trading)                                                                                                          |       |        |       |     |       |        |       |     |       |     |       |
| Unit prices                                                                                                                            |       |        |       |     |       |        |       |     |       |     |       |
| High                                                                                                                                   | ** ** | **33.95**   |       | 23.86    | ** ** | **30.74**   |       | 27.58    |       | 17.98    |       |
| Low                                                                                                                                    | ** ** | **15.01**   |       | 18.90    | ** ** | **19.20**   |       | 16.55    |       | 13.50    |       |
| Close                                                                                                                                  | ** ** | **20.10**   |       | 20.40    | ** ** | **22.30**   |       | 26.49    |       | 17.90    |       |
| Average daily volume (thousands)                                                                                                       | ** ** | **975**     |       | 597      | ** ** | **706**     |       | 656      |       | 420      |       |

 

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(1)             Per unit amounts (with the exception of perunit distributions) are based on weighted average trust units outstanding plustrust units issuable for exchangeable shares.

(2)             This is a GAAP measure and a change from thenon-GAAP measure reported in prior quarters. Refer to non-GAAP section.

(3)             Net income per unit is based on net incomeafter non-controlling interest divided by weighted average trust unitsoutstanding (excluding trust units issuable for exchangeable shares).

(4)             Based on number of trust units outstanding ateach distribution date.

(5)             Net debt excludes the current unrealized riskmanagement contracts asset and liability and the current portion of futureincome taxes.

(6)             Includes trust units issuable for outstandingexchangeable shares based on the period end exchange ratio.

(7)             Represents total consideration for thecorporate acquisition including fees but prior to working capital, assetretirement obligation and future income tax liability assumed on acquisition.

(8)             Company interest reserves are the grossinterest reserves plus the royalty interest prior to the deduction of royaltyburdens.

 

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**QUARTERLYHISTORICAL REVIEW**

 
| **(Cdn $ millions, except per** | ** ** | **2008**    | ** ** | **2007** | ** ** |
|-----------------------------------------------------|------------|-------------|------------|----------|------------|
| **unit amounts)**                              | ** ** | **Q4**      | ** ** | **Q3**   | ** ** | **Q2** | ** ** | **Q1** | ** ** | **Q4** | ** ** | **Q3** | ** ** | **Q2** | ** ** | **Q1** | ** ** |
| **FINANCIAL**                                       |       |        |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Revenue before royalties                            | ** ** | **300.8**   |       | 485.7    |       | 512.0 |   | 407.9 |   | 338.0 |   | 300.2 |   | 305.6 |   | 307.8 |   |
| Per unit (1)                                        | ** ** | **1.38**    |       | 2.24     |       | 2.38 |   | 1.91 |   | 1.59 |   | 1.42 |   | 1.46 |   | 1.48 |   |
| Cash flow from operating activities (2)        | ** ** | **209.4**   |       | 251.4    |       | 273.4 |   | 209.9 |   | 173.7 |   | 179.6 |   | 179.4 |   | 172.3 |   |
| Per unit – basic (1)                           | ** ** | **0.96**    |       | 1.16     |       | 1.27 |   | 0.98 |   | 0.82 |   | 0.85 |   | 0.86 |   | 0.83 |   |
| Per unit – diluted                             | ** ** | **0.96**    |       | 1.16     |       | 1.27 |   | 0.98 |   | 0.82 |   | 0.85 |   | 0.86 |   | 0.83 |   |
| Net income                                          | ** ** | **82.7**    |       | 311.7    |       | 57.3 |   | 81.3 |   | 106.3 |   | 120.8 |   | 184.9 |   | 83.3 |   |
| Per unit – basic (3)                           | ** ** | **0.38**    |       | 1.46     |       | 0.27 |   | 0.39 |   | 0.51 |   | 0.58 |   | 0.90 |   | 0.41 |   |
| Per unit – diluted                             | ** ** | **0.38**    |       | 1.46     |       | 0.27 |   | 0.38 |   | 0.51 |   | 0.58 |   | 0.89 |   | 0.41 |   |
| Distributions                                       | ** ** | **127.2**   |       | 171.3    |       | 144.7 |   | 126.8 |   | 125.8 |   | 125.0 |   | 124.1 |   | 123.1 |   |
| Per unit (4)                                        | ** ** | **0.59**    |       | 0.80     |       | 0.68 |   | 0.60 |   | 0.60 |   | 0.60 |   | 0.60 |   | 0.60 |   |
| Total assets                                        | ** ** | **3,766.7** |       | 3,687.5  |       | 3,664.3 |   | 3,592.6 |   | 3,533.0 |   | 3,460.8 |   | 3,432.8 |   | 3,540.1 |   |
| Total liabilities                                   | ** ** | **1,624.6** |       | 1,530.8  |       | 1,689.6 |   | 1,560.4 |   | 1,491.3 |   | 1,421.4 |   | 1,415.3 |   | 1,526.6 |   |
| Net debt outstanding (5)                            | ** ** | **961.9**   |       | 773.2    |       | 756.1 |   | 770.1 |   | 752.7 |   | 699.8 |   | 653.9 |   | 729.7 |   |
| Weighted average trust units (6)                    | ** ** | **218.3**   |       | 216.6    |       | 215.2 |   | 213.8 |   | 212.5 |   | 210.9 |   | 209.5 |   | 207.9 |   |
| Trust units outstanding and issuable (6)       | ** ** | **219.2**   |       | 217.4    |       | 215.8 |   | 214.7 |   | 213.2 |   | 211.7 |   | 210.2 |   | 208.7 |   |
| **CAPITAL EXPENDITURES**                            |       |        |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Geological and geophysical                          | ** ** | **3.7**     |       | 1.3      |       | 16.4 |   | 5.5 |   | 3.0 |   | 2.9 |   | 4.1 |   | 4.9 |   |
| Land                                                | ** ** | **17.1**    |       | 18.6     |       | 57.8 |   | 28.8 |   | 42.6 |   | 33.0 |   | 1.7 |   | 0.2 |   |
| Drilling and completions                            | ** ** | **117.1**   |       | 91.4     |       | 32.6 |   | 64.4 |   | 75.2 |   | 73.4 |   | 25.8 |   | 55.1 |   |
| Plant and facilities                                | ** ** | **30.5**    |       | 24.2     |       | 24.1 |   | 11.6 |   | 17.9 |   | 21.1 |   | 16.3 |   | 16.8 |   |
| Other capital                                       | ** ** | **1.0**     |       | 0.9      |       | 0.4 |   | 1.0 |   | 0.6 |   | 1.5 |   | 0.6 |   | 0.5 |   |
| Total capital expenditures                          | ** ** | **169.4**   |       | 136.4    |       | 131.3 |   | 111.3 |   | 139.3 |   | 131.9 |   | 48.5 |   | 77.5 |   |
| Property acquisitions (dispositions) net            | ** ** | **27.6**    |       | 13.1     |       | 0.3 |   | 10.1 |   | 5.0 |   | 27.3 |   | 10.0 |   | 0.2 |   |
| Total capital expenditures and net  acquisitions    | ** ** | **197.0**   |       | 149.5    |       | 131.6 |   | 121.4 |   | 144.3 |   | 159.2 |   | 58.5 |   | 77.7 |   |
| **OPERATING**                                       |       |        |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Production                                          | ** ** | ** **  |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Crude oil (bbl/d)                                   | ** ** | **28,935**  |       | 28,509   |       | 27,541 |   | 29,064 |   | 28,682 |   | 28,437 |   | 28,099 |   | 29,520 |   |
| Natural gas (mmcf/d)                                | ** ** | **195.1**   |       | 192.0    |       | 194.7 |   | 204.3 |   | 187.4 |   | 173.3 |   | 176.7 |   | 183.0 |   |
| Natural gas liquids (bbl/d)                         | ** ** | **3,858**   |       | 3,822    |       | 3,906 |   | 3,856 |   | 4,067 |   | 3,795 |   | 4,088 |   | 4,161 |   |
| Total (boe per day 6:1)                             | ** ** | **65,313**  |       | 64,325   |       | 63,896 |   | 66,976 |   | 63,989 |   | 61,108 |   | 61,637 |   | 64,175 |   |
| Average prices                                      |       |        |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Crude oil ($/bbl)                                   | ** ** | **56.26**   |       | 114.20   |       | 118.32 |   | 89.72 |   | 77.53 |   | 73.40 |   | 65.21 |   | 60.79 |   |
| Natural gas ($/mcf)                                 | ** ** | **7.48**    |       | 8.68     |       | 10.41 |   | 7.80 |   | 6.32 |   | 5.52 |   | 7.38 |   | 7.75 |   |
| Natural gas liquids ($/bbl)                         | ** ** | **45.22**   |       | 82.87    |       | 82.29 |   | 68.54 |   | 62.75 |   | 55.64 |   | 52.76 |   | 48.04 |   |
| Oil equivalent ($/boe)                              | ** ** | **49.93**   |       | 81.42    |       | 87.73 |   | 66.67 |   | 57.26 |   | 53.28 |   | 54.37 |   | 53.18 |   |
| **TRUST UNIT TRADING**                              |       |        |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| (based on intra-day trading)                        | ** ** | ** **  |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Unit prices                                         | ** ** | ** **  |       |     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| High                                                | ** ** | **22.55**   |       | 33.30    |       | 33.95 |   | 27.06 |   | 21.55 |   | 22.60 |   | 23.86 |   | 23.02 |   |
| Low                                                 | ** ** | **15.01**   |       | 22.33    |       | 25.19 |   | 20.00 |   | 18.90 |   | 19.00 |   | 20.78 |   | 20.05 |   |
| Close                                               | ** ** | **20.10**   |       | 23.10    |       | 33.95 |   | 26.38 |   | 20.40 |   | 21.17 |   | 21.74 |   | 21.25 |   |
| Average daily volume (thousands)                    | ** ** | **1,523**   |       | 841      |       | 659 |   | 863 |   | 624 |   | 503 |   | 599 |   | 658 |   |

 

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(1)             Per unit amounts (with the exception of perunit distributions) are based on weighted average trust units outstanding plustrust units issuable for exchangeable shares.

(2)             This is a GAAP measure and a change from thenon-GAAP measure reported in prior reports. Refer to non-GAAP section.

(3)             Net income per unit is based on net incomeafter non-controlling interest divided by weighted average trust unitsoutstanding (excluding trust units issuable for exchangeable shares).

(4)             Based on number of trust units outstanding ateach distribution date.

(5)             Net debt excludes the current unrealized riskmanagement contracts asset and liability and the current portion of futureincome taxes.

(6)             Includes trust units issuable for outstandingexchangeable shares based on the period end exchange ratio.

 

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